Basic Mud Logging

Basic Mud Logging Guide Version 2.0

Basic Mud Logging

INTRODUCTION The drilling rig is a complex system consisting of people and equipment who must work safely under extreme conditions. The rigs can range from a truck mounted work-over rig to a large ocean going drill ship. Rigs are primarily divided into two major categories; land and marine. It is important to be cognizant of each rig type so that you as a logging engineer will be able to competently participate in the safe and hopefully productive completion of the well. The drilling rig and personnel perform very special functions at different times. In the oil field, the customary unit of measure of rig production is the foot. In many parts of the world the meter is used in place of the foot; a meter equals about 3.281 feet. The foot is a convenient unit by which to measure the product of a drilling operation and pay the contractor who drilled or “made the hole.” It is a fact of life in the drilling industry, however, that the cost per foot of making hole varies directly in relation to the depth to which the foot of hole is drilled. The deeper the hole, the more costly each additional foot drilled. Most rigs are owned by an individual or a firm known as a drilling contractor. Companies engaged in finding, producing, or refining petroleum, own the majority of leases, or wells. These companies are often called operators, or operating companies. Representing the operator is the company man or drilling supervisor. The operator hires or contracts, the drilling contractor to drill the well. In most cases, drilling contracts are drawn on a day work basis, which means that payment is made for each day the rig is used, plus certain extras. Both the operator and the contractor are interested in such details as the time required for completing the job; the safety of the equipment, property, and personnel throughout the operation; and the ability of both the men and the equipment to do acceptable work. The mud logging engineer needs to become familiar with the basic equipments, techniques and terms used in drilling operations. Although he has no direct responsibility for the drilling or the rig, the mud logging engineer has to be conversant with the equipment and procedures so that he can advise on certain aspects and so that he can understand the effects of drilling methods affecting the parameters he uses for his interpretation. It is also important for the mud logging engineer to develop good working relationship with the drilling personnel to keep a two-way flow of information and gain the greatest benefits for the operation. This guide is rather meant as a briefing instruction to those mud logging engineers who are newly involved in rig drilling operations, facing new concepts, routines and formats. It is also tried to introduce and illustrate modern or future development that may be new to some “old hands” with no recent exposure to the actual work. However, owing to the fast development of techniques and methods, even this booklet will be out dated partly in very short time.

PetroServices GmbH Training Center

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Basic Mud Logging

RIG TYPES Drilling rigs are classified according to field operations into two major types (land rigs and off shore rigs) which by turn reclassified into other types depending on each rig capability and working environment. Accordingly, rig type can be one of the followings:

 Land rigs: Land rigs are generally either wheel mounted portables or a component system that must be moved by trucks and cranes. The drilling floor generally sits on top of a steel substructure that could be 30 feet high or more. A drilling mast (derrick) is attached to and raised above the floor. In general, the deeper wells need a larger, taller rig. The mast must be capable of supporting the vertical load and weight of the stacked drill pipe. It must also withstand wind loads of 100 to 130 miles per hour. Shallow wells and wells being completed or repaired will probably use a portable rig. This rig can be driven to the well site, raised up hydraulically and guy wired in place. When the well is completed, the mast is hydraulically lowered and the rig is driven off.


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Basic Mud Logging  Offshore rigs: One of the hazards of offshore drilling is the hostile environment. The effects of greater water depths, storms, wave action and uncertain exploratory data all greatly increase the financial risks. The exploratory wells must be drilled and a reserve potential established that could justify these costs. These exploratory wells seek to establish new reservoir locations and sizes. Once drilled and evaluated, the exploratory well is most often plugged and abandoned. This results in the use of marine rigs for offshore drilling. The development wells are usually drilled from fixed platforms specially designed to exploit the reserves of the reservoir. The platform is also used for production facilities after all drilling operations are complete. The environment also determines which type of marine rig will be used. Each rig has advantages and disadvantages when used in different water depths and weather conditions. The type of marine rig also can depend on problems involved in getting the rig on location and keeping it stationed in the desired position. The choices include the jackup rig, semisubmersible rig, the submersible rig, the drill ship, the platform rig, the inland barge rig, and the tension leg platform.

Different types of offshore rigs


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Basic Mud Logging 1. Jackup rigs: The jackup rig has replaced the submersible rig as a fixed drilling platform. It is less costly to build and can operate in up to 600 feet of water. It is ideal for soft ocean sediments found in river deltas. The jackup rig consists of a watertight hull and three or more mobile legs. The legs are raised up to allow the vessel to be towed to a location. Then the legs are carefully jacked down until each rests on the seabed. The hull is then jacked up on the legs until it is above the predicted height of storm waves. This height depends on the area and the season. It varies in the Gulf of Mexico from 25 to 35 feet and in the North Sea up to about 95 feet for the worst storm conditions to be expected. Because the jackup also sets on the seabed, it does not have heave problems. It can have vessel motion problems during bad weather if jacked to the top of the legs. This eliminates the need for most motion compensation equipment and special mooring and anchoring equipment. To move rig between close locations the platform is lowered down the legs until it floats then the legs are jacked up to the maximum height. The whole rig can then be towed by means of two boats. In long rig moves or across oceans the whole rig is normally carried on a huge carrier. Disadvantages include its difficulty in towing, especially in rough seas; the legs must be removed during long moves.

Jackup offshore rig


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Basic Mud Logging 2. Semi-submersible rigs: Semi-submersible rigs are floating rigs supported on pontoons. A common design consists of four, five or six legs. Older semi-submersibles are kept on location by means of anchors and chains, whereas some of the newer ones are kept on location by means of thrusters. The pontoons can be re-floated to change locations. They can be towed easily or even self-propelled to the new location. The semi-submersible rig evolved from the older submersible rigs. It can provide a relatively stable drilling platform. It can operate under more serve weather and sea conditions and in water depths from 600 to 4,000 feet. The semi-submersible rig contains a normal working deck plus columns and pontoons under the deck. These pontoons are ballasted to a water depth that causes the upper deck to remain high above the water. Semi-submersible rigs are the elephants of the offshore rigs, capable to continue operation in bad weather. Semi-submersible rigs move with the tide the drilling penetration rate must be corrected for the influence of the tidal heave. The disadvantages of semi-submersible rigs are that they require marine risers and a subsea stack, having limited cargo capacity and require support vessels.

Semi-submersible offshore rig


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Basic Mud Logging 3. Drill ship: Drill ships are ships specially built and modified to drill in deep water or in operations that are not suitable for semi-submersible rigs. Drill ships are self-propelled and can carry larger loads of drilling supplies. This makes them more mobile and self-supporting in remote ocean areas. The drill ship is capable of drilling in waters up to 9,000 feet. It also offers advantages of faster travel times, are self-propelled, and can use dynamic positioning systems. Drill ships are differentiated from other offshore drilling units by their easy mobility. While semi-submersible rigs can also drill in deep waters, drill ships are able to propel themselves from well to well and location to location, unlike semi-submersible, which must rely on an outside transport vessel to transfer them from place to place. The disadvantages of drill ships include high salaries for the ship’s crew who are not directly involved in the drilling operations. In addition, the drill ship is greatly affected by wave motion (heave) and drifting. This requires a motion compensation system, a marine riser system, and/or a mooring and anchoring system or thrusters for dynamic positioning. Transocean, Pride, Seadrill, Frontier Drilling and Noble are a few of the companies that own and operate drill ships globally.

Drill ship


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Basic Mud Logging 4. Platform rigs: If the exploration drilling program is successful in finding a commercial reservoir, a development program must be planned. All facilities needed to drill, produce, store and transport the hydrocarbons must be designed, fabricated and installed on the site. All fixed platforms must be able to withstand the environmental forces of its region. This could include wind, waves, currents, ice, earthquakes and soil conditions. The platform generally consists of four to eight piles or legs resting or driven into the seabed. Drilling slots on the platform are arranged in a grid system. The actual drilling rig will be skidded from slot to slot for each well. The individual wells will be drilled at an angle to allow for efficient production of the reservoir. A fixed drive pipe extends from a subsea template to the substructure of the platform. The BOP stack is connected to the fixed drive pipe for each well slot as it is drilled. Because of its location, the stack is easier to install, repair or change sizes.

Offshore platform


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Basic Mud Logging 5. Inland barge rigs: A drilling structure consisting of a barge upon which the drilling equipment is constructed. When moved from one location to another, the barge floats. When stationed on the drill site, the barge can be anchored in the floating mode or submerged to rest on the bottom. Typically, inland barge rigs are used to drill wells in marshes, shallow inland bays, and areas where the water covering the drill site in not too deep. Also called swamp barge. The inland barge rig is the oldest form of marine rig. It consists of two hulls, which are connected by legs. The upper hull is air tight and provides the buoyancy necessary to float the rig to each site. The rig is positioned over the site and the lower hull is flooded. This causes the rig to sink until it rests on the sea floor. After drilling the well, the rig is re-floated and moved to a new location. The inland barge rig is limited to working in relatively shallow water, less than 50 feet normally. They are also hard to move to new locations.

Inland barge rig


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Basic Mud Logging 6. Tension leg platforms: The Tension Leg Platform is one of the newest types of rig available. It is a combination of a semi-submersible rig and a platform rig. It is used strictly for production drilling. Normally, some of the wells in the field have already been drilled, and then the TLP is positioned over the pre-drilled wells and the production lines run to the existing wellheads. They are set up with drilling equipment in the event other wells need to be drilled, or any existing wells must be worked over. The current technology allows the TLPs to work in up to 5,000 feet of water. The platform is permanently moored by means of tethers or tendons grouped at each of the structure's corners. A group of tethers is called a tension leg. A feature of the design of the tethers is that they have relatively high axial stiffness (low elasticity), such that virtually all vertical motion of the platform is eliminated. This allows the platform to have the production wellheads on deck (connected directly to the subsea wells by rigid risers), instead of on the seafloor. This allows a simpler well completion and gives better control over the production from the oil or gas reservoir, and easier access for downhole intervention operations. TLP's have been in use since the early 1980s. The first Tension Leg Platform was built for Conoco's Hutton field in the North Sea in the early 1980s. Larger TLP's will normally have a full drilling rig on the platform with which to drill and intervene on the wells. The smaller TLPs may have a workover rig, or in a few cases, no production wellheads located on the platform at all.

Tension leg platform rig


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Basic Mud Logging

LAND RIG COMPONENTS Simple diagram of a land drilling rig and its components is illustrated in the next figure. The typical rig shown in the next figure shows the layout of most component parts. Use this layout as you read about each system on the rig. Not all rigs are arranged the same. Newer rigs use modular designs and space saving techniques.

The main rig components are as follow: 1. Crown Block and Water Table 2. Cat-line Boom and Hoist Line 3. Drilling Line 4. Monkey board 5. Traveling Block 6. Top Drive 7. Mast 8. Drill Pipe 9. Doghouse 10. Blowout Preventer 11. Water Tank 12. Electric Cable Tray 13. Engine Generator Sets 14. Fuel Tanks 15. Electric Control House 16. Mud Pump 17. Bulk Mud Components Storage 18. Mud Pits 19. Reserve Pits 20. Mud Gas Separator 21. Shale Shaker 22. Choke Manifold 23. Pipe Ramp 24. Pipe Racks 25. Accumulator

Land rig components

However, all rigs must have five basic systems or operations performed. These include: 1. Hoisting system: used to raise and lower drill pipe, casing, and tubing. 2. Circulating system: used to remove cutting and maintain pressure in the well bore. 3. Rotating system: used to turn the drill stem to make hole. 4. Power production system: used to produce mechanical and electrical power. 5. Blowout prevention system: used to seal off the well bore to control formation fluids.


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Basic Mud Logging 1. Derrick or mast: A standard derrick is a structure with four supporting legs resting on a square base. It can be assembled piece by piece each time a well is drilled. In contrast, the mast is assembled once when it is manufactured. After manufacture, it remains a single unit each time a well is drilled. When a mast is raised and lowered, it looks something like the blade of a huge jackknife being opened and closed. As a result, masts are sometimes referred to as jackknife masts. For most offshore drilling rigs, the derrick is the standard.

The mast or derrick is erected on substructure that serves two main purposes:

a

1. To support the rig floor, providing space for equipment and workers. 2. To provide space under the rig floor for special, large valves called blowout preventers. The substructure supports not only the rotary table, but also the full load of the drill string when the string is suspended in the hole by the slips. It also supports a string of casing when the casing is being run in the hole by an arrangement of slips resting on the rotary. The rig floor also holds the draw works, the driller’s control panel, the doghouse, and other related equipment. Derricks and masts are rated according to the vertical load they can carry and the wind velocity they can withstand from the side. Derrick loadbearing capacity figures may vary from 250,000 to 1,500,000 pounds. A typical mast or derrick can withstand winds of about 100 to 150 miles per hour with the racks full of pipe and without the need for external bracing. The derrick and its substructure support the weight of the drill string at all times, whether the drill string is suspended from the crown block or resting in the rotary table. The height of a derrick does not affect its load-bearing capacity, but the length of the sections of drill string to be removed from the hole is limited by the height of the derrick. This is because the crown block must be sufficiently elevated above the rig floor to permit the withdrawal and temporary storage of the drill string when it is pulled from the well to change bits or for other reasons. Drill pipe is pulled and racked in stands. A stand usually consists of three joints of pipe, each about 30 feet long. Such a stand, having a total length of some 90 feet, can be accommodated in a derrick that is 136 feet high or higher. Rigging-up time is the time spent to assemble a mast into the vertical position on-site. It also includes the time to install the power unit, all cables and piping. Masts are used for lighter work.


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Basic Mud Logging 2. Hoisting system: The draw works, sometimes called the hoist, is a big heavy piece of machinery that consists of a revolving drum around which the wire rope, called the drill line, is spooled or wrapped. It also has a cat-shaft, a kind of axle that crosses through the draw works that has a revolving drum (called a cat-head spool) on both end and two special cat-heads. Several other shafts, clutches, and a chain-and-gear drive facilitate speed and direction changes. An integral part of the draw works is a system of speed changes (transmission system). This transmission system as shown in the next figure gives the driller a wide choice in hoisting the pipe. Thus, the drum of the hoist may be considered as having a minimum of four and often as many as eight speeds.

Draw work transmission system


Draw work system

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Basic Mud Logging The origin of the term draw works is not actually known, but probably is related to the fact that part of the function of the draw works is to draw pipe out of the hole. The two main purposes of the draw works are: 1. To lift pipe out of the hole. 2. To lower the pipe back into the hole. Wire rope is reeled, or spooled, on a drum in the hoist. When the draw works is engaged, the drum turns and, depending on the direction it either turns, reels in the drill line to raise the traveling block or lets out the line to lower it. Since the drill string is attached to the block by the elevators, the string is thus raised or lowered. One of the outstanding features of the hoist is the brake system, which enables the driller to easily control a load of thousands of pounds of drill pipe or casing. On most rigs, there are at least two brake systems. One brake is mechanical and can bring the entire load to a full stop. The other brake is hydraulic or electric and can control the speed of the descent of a loaded traveling block, although it is not capable of bringing it to a complete halt. Another feature of the draw works is the cat-shaft with its two special cat-heads. The makeup (spinning) cat-head on the driller’s side of the draw works is used to spin up and tighten the drill pipe joints. The other, located opposite the driller’s position on the draw works, is the breakout cat-head. It is used to loosen the drill pipe when the pipe is withdrawn from the hole.

Draw works cat-head PetroServices GmbH Training Center

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Basic Mud Logging 3. Blocks and drilling line: The traveling block, crown block, and drilling line are the three components whose function is to support the load of drill pipe in the derrick as it is lowered into or pulled from the hole. During drilling operations, this load consists of the hook, swivel, kelly, drill pipe, drill collars, and a bit attached to the bottom of the drill collars. During cementing operations, a string of special pipe called casing, often a heavier load than the drill pipe and drill collars, has to be lowered into the hole and cemented. Drill line is usually made of wire rope that generally ranges from 1.5 inches to 1.75 inches in diameter. Wire rope is similar to common fiber rope, but wire rope, as the name implies, is made of steel wires and is a complex device.

Although the wire rope looks very much like cable, it is specially designed for the heavy loads encountered on the rig. To achieve the greatest economy from the use of wire on a drilling rig, the line selected should be in accord with both the load requirements and the design of the sheaves in the traveling block and crown block through which the line must travel. The line should be frequently inspected to ensure that it is in good condition. The drill line should be moved periodically (slipped in the field term) so that it wears evenly as it is used. Cut off procedures should take into account the amount of usage or work done by the wire rope. Wire rope wear is determined by the weight, distance, and movement of wire rope travel over a given point (ton-miles). Traveling block The drill line is threaded over a crown block sheave and lowered down to the rig floor. On the rig floor rests (temporarily) another very large set of pulleys or sheaves called the traveling block. The end of the line is threaded through one of the traveling block sheaves and is raised again up to the crown block. There the line is threaded over a sheave in the crown block, lowered back down, and threaded through the traveling block. This is done a number of times until the correct number of lines has been strung up. The number of lines, of course, is only one; but, since the drill line is threaded through the crown block and traveling block several times, it gives the effect of many lines. The number of lines strung depends on the weight to be supported. The more weight to be supported, the more lines that are needed and vice versa. Once the last line has been strung over the crown block sheaves, the end of the line is lowered down to the rig floor and attached to the drum on the draw works. Several wraps of line are then taken around the draw works drum. The part of the drill line running out of the draw works up to the crown block is called the fast line; “fast” because it moves as the traveling block is raised or lowered on the derrick. The end of the line that runs from the crown block down to the supply reel is then secured. This part of the line is called the deadline; “dead” because, once it is secured, it does not move. Mounted on the rig substructure is a device called a deadline anchor. The deadline is firmly clamped to the anchor.


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Basic Mud Logging 4. Elevators: Two elevators are hung from the hook on the elevator bails and are used for latching around the drill pipe in order to lift it. Elevators are of many slightly differing designs and sizes for use with different pipe sizes, drill collar and casing sizes. They are not used during the drilling operation but are necessary for lifting the pipe during tripping operation. Elevators are a set of clamps that are latched onto the drill pipe to allow the driller to raise or lower the drill string out of or into the hole. The driller lowers the traveling block and the elevators down to a point where the drill crew can latch the elevators onto the drill pipe.

5. Slips: These devices are used to hold the weight of the drill string when it is not supported by the hook (during connections or tripping time). Slips are made of hinged sections with a single opening. They are placed around the pipe, their tapered outer sections fitting against either the inside surface (bowl) or the master bushing or against the inserts. As the pipe is lowered, the slips tapered section causes them to close tightly around the pipe. The downward motion of the drill pipe must be stopped with the draw works brakes, not with the slips. The drawing shows the effects of stopping the motion of the pipe with slips. This can occur when the floor hands are not careful to set the slips at the proper time when the driller has stopped the pipe. Do not let the slips "ride" on the pipe while the pipe is being pulled out of the hole. This practice accelerates the wear on the gripping elements of the slip. It also risks having the slip ejected from the master bushing bowl when a tool joint comes through and causing possible injury to personnel. Be careful not to catch the tool joint box in the slips when the driller slacks off. This often happens when coming out of the hole and the driller does not pick up high enough for the slips to fall around the pipe properly. This can ruin the slips, damage the tool joint box and damage the body of the pipe.


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Basic Mud Logging 6. Rotating equipments: The rotating equipment from top to bottom consists of the swivel, the kelly, the rotary table, the drill string and the bit. The drill string is the assembly of equipment between the swivel and the bit, including the kelly, drill pipe and drill collars. The term drill string simply refers to the drill pipe and drill collars; however, in the oil field, drill string, is often used to mean the whole works.  Swivel: The swivel is a remarkable mechanical device; it is attached to the traveling block by a large bail. The swivel has three main functions: 1. It supports the weight of the drill string. 2. It allows the drill string to rotate. 3. It provides a pressure tight seal and passageway for the drilling mud to be pumped down the inside of the drill string. The fluid comes in through the gooseneck, a curved pipe that connects the swivel to a hose (kelly hose) carrying the drilling fluid from the mud pumps. The fluid then passes through the wash pipe, a vertical tube in the center of the swivel body, and into the kelly and drill string.

Swivel


Drill string

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Basic Mud Logging  Kelly and rotary table: The kelly is a three, four, or six-sided length of pipe, about 50 feet long, that is the upper part of the drill string. It serves as a passageway for the drilling fluid on its way into the hole and transmits the rotary movement to the drill pipe and bit. An upper kelly cock is a special valve that can often be recognized as a bulge on the upper part of the kelly. The kelly cock can be closed to shut off well pressure coming up from inside the drill string. Most kelly cocks require a special wrench to operate the closing valve. A lower kelly cock (also called a drill pipe safety valve or a drill string valve) is usually made up between the lower end of the kelly and the top joint of drill pipe. When the kelly is pulled up high above the rotary table, as it usually is when a joint of pipe is being added to the drill string (i.e., when a connection is being made), the upper kelly cock cannot be reached easily should it be necessary to close in the drill string. However, the lower kelly cock is readily accessible when the kelly is raised. The kelly’s upper end is connected to the swivel, and its lower end is connected to the drill pipe. The drill pipe screws into a device called a kelly saver sub, or a saver sub. The sub is a short, connecting fitting that screws into the bottom of the kelly. The bottom threads on the sub are temporarily joined with threads on the top of each length of drill pipe that is added to the string. The sub saves wear on the threads of the kelly; when the threads of the sub become worn, the sub is replaced and rethreaded. The kelly fits into a corresponding square or hexagonal opening in a device called a kelly, or drive bushing. The kelly bushing fits into a part of the rotary table called the master or rotary bushing. As the rotary bushing rotates, the kelly rotates; and as the kelly rotates the drill string and bit. Rotary drilling derives its name from the rotary table. The rotary table is powered by the compound or by its own electric motor.

Rotary table


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Basic Mud Logging  Top drive system: The top drive system is replacing the kelly and rotary table on many rigs. This one piece of equipment replaces both the kelly and rotary table. The basic model is an equipment with one pinion powered by a hydraulic motor located on top of the gearbox. Top drive system advantages: • •

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• • • • • •

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The top drive make-ups and breaks-out many connections, thereby reducing the hazards of rotary tongs and spinning chain. The pipe handling features use hydraulic arms to move drill pipe and drill collars to and from the V-door and monkey board, thereby reducing strenuous work and increasing pipe handling safety. The automatic, driller operated pipe elevators eliminate accidents caused by drilling crews operating elevators manually during under balanced drilling operations. The top drive increases safety by reducing BOP wear and allowing the BOP/rotating head to pack off against round tubulars, not a square or hex Kelly. Well control capability is greatly enhanced because of the ability to screw into the string any point in the derrick to circulate drilling fluids. Remote operated Kelly valve reduces (optional) mud spillage when back reaming or breaking off after circulating above the rig floor. Reduce total drilling costs by increasing drilling efficiency. No drilling downtime caused by the inability to engage the kelly bushing in the rotary table. Eliminate time lost due to picking up or racking back the swivel and kelly when going from tripping to drilling or vice versa. Increase penetration rates when spilling in or drilling the surface hole. Eliminate rat hole contractor charges and costs of rat hole, mouse hole and conductor pipe in many cases. Make connections on the bottom while directional drilling, eliminating the need to re -orient the tool face after each connections. Spend more time on bottom making the hole and less time making connections, tripping, surveying, reaming and other non drilling rig functions. Continuous rotation and circulation during full movement of The Drill String. The most important feature of the top drive is the ability to rotate and pump continuously while reaming into or out of the hole. Continuous rotation means substantially reduced friction when removing the string from or tripping back into directional or horizontal wells. Top drive system


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Basic Mud Logging  Drill string: The drill string is made up of the drill pipe and special, heavy-walled pipe called drill collars. Each length of drill pipe is about 30 feet long and is called a joint of pipe. Each end of each joint is threaded. The end of the joint with the interior threads is known as the box, and the end of the joint with the exterior threads is called the pin. When pipe is made up, the pin is stabbed into the box and the connection tightened. The threaded ends of the pipe are called tool joints and are actually separate parts that are welded onto the ends of the drill pipe by the manufacturer who cuts the threads to industry specifications. Drill collars, like drill pipe, are steel tubes through which mud can be pumped. Drill collars are heavier than drill pipe and are used on the bottom part of the drill string to put weight on the bit. This weight presses down on the bit to get it to drill. Drill collars are about 30 feet long and, unlike the drill pipe that has tool joints welded on, they have the boxes and pins cut into them.

Heavy weight drill pipes


Drill collars

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Basic Mud Logging  Stabilizers: These are run between the drill collars and are of a blade type construction. Drilling fluid can pass freely between the blades while the outer edge of the blades contacts the wall of the hole and holds the drill collars firmly centered in the hole. They do exactly as their name implies, they provide stability to the bit and collars. This is important as it improves bit life, in addition to keeping the direction of the hole under control. The purpose of the stabilizers is to centralize the collars and to keep the hole straight. The faces of the stabilizer fins are coated with hard material such as tungsten carbide to reduce wear and tear.

 Reamers: Reamers usually have the same diameter as the bit and run a little distance above it. The reamer function is to cut the hole out to full size behind the bit. There are many types of reamers depend on the formation that they will pass through. For example, roller reamers are classified into three roller cutter types: • Soft formation cutters deliver maximum reaming action in soft formations like soft limestone and shale. Service life of cutter is enhanced with hard end and carburized teeth. • Medium to hard formation cutters are most suitable for cherty formations to hard formations such as dolomite, hard limestone and chert. • Very hard formation cutters deliver reliable reaming performance in hard, abrasive and semi-abrasive formations such as granite and sand.  Bumper Sub: Bumper subs are currently used in offshore operations to permit a constant weight to be carried on the bit while drilling, regardless of the vertical motion imparted to the drill pipe by drilling vessel heave. The vertical motion of the lower end of the drill pipe (the bumper sub end) may be appreciably greater than the vessel heave. Therefore, the necessary stroke of bumper subs for successful operation is greater than thought in the past. In addition, there is an appreciable tendency of the drill pipe to buckle above the unbalanced type of bumper sub. Thus, more drill collars than previously used should be carried above unbalanced bumper subs to keep drill pipe straight.


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Basic Mud Logging  Rotary & crossover sub: Rotary subs have two primary applications. They can be used to crossover from one connection size to another or as the disposable component used to extend the connection life of a more expensive drill stem member. Rotary subs are available with box x pin, box x box or pin x pin connections. The rotary subs include the following types: Straight OD sub is used to connect drill string members that have a similar outside diameter. The drill bit, downhole tools, heavy weight drill pipe and drill pipe can be crossed over using a straight OD sub. Reduced section sub is used to connect drill stem members that have different diameters that warrant the cross-sectional change necessary to accommodate different connections. This sub would be used to crossover large OD drilling tools or a tapered drill collar string. Saver sub is used to extend the life of the kelly by taking the connection wear each time it is made up to a drill string component. The saver sub connection is sacrificed because it can be easily repaired or inexpensively replaced. The saver sub can be equipped with a rubber protector to reduce BOP equipment and casing wear resulting from contact damage with the lower kelly connection.

 Top drive sub: Top Drive Subs serve as the sacrificial element between the drill string and the top drive, reducing repair and maintenance costs. The top drive sub can easily be repaired or replaced in the event the lower pin threads become galled or damaged. These tools are manufactured from selected bars of alloy steel, heat treated to provide the strength and toughness required to carry the entire weight of the drill string.

 Bent sub: This is a non-straight sub designated with different bending angles, it is fitted in the deviating bottom hole assembly above the mud motor to drill deviated holes. The angle of bending is selected according to the inclination building rate and the length of the interval to be drilled with this sub

 Lift sub: A Lift Sub enables the safe, efficient handling of straight OD tubulars such as drill collars, shock tools, jars, directional equipment and other tools by using the drill pipe elevators. Lifting subs can be either tapered or square shoulder types and are made from AISI 4145/4140. They are available in all diameters and lengths.

 Lift plugs: Lift plugs are of heat treated steel alloy. Crown sections are bored out to reduce weight. They are available in all sizes with or without lifting bail.


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Basic Mud Logging  Bits: There are many types of bits that have been developed through the years for more efficient drilling. Among these types are: •

Rock bits: Roller cone or rock bits have cone-shaped steel devices called cones that are free to turn as the bit rotates. Bit manufacturers either cut teeth out of the cones or insert very hard tungsten carbide buttons into the cones. The longer the teeth of the bit, the softer the formation need to be and vice versa. The teeth can be made of the same material as the cones (milled teeth) or made of hard (e.g. tungsten carbide) inserts, hence insert bits. The teeth are responsible for actually cutting or gouging out the formation as the bit is rotated. All bits have passages drilled through them to permit drilling fluid to exit. Most bits have nozzles that direct a high-velocity stream or jet of drilling fluid to the sides and bottom of each cone so that rock cuttings are swept out of the way as the bit drills.

•

PDC bits: Polycrystalline Diamond Compact (PDC) bits do not have cones, but they do have tungsten carbide teeth. Several hundred diamonds are embedded onto the edges of the teeth. Since diamonds are so hard, diamond bits are especially suited for drilling hard formations but can also be used very effectively on soft formations. Such bits can stay on bottom for a long time and drill long distances. However, on the negative side, PDC bits are extremely sensitive to pyrite in the formation and metal junk as debris that may come from a cast iron casing shoe. In addition, their penetration rate in shale is relatively poor and their cost much higher than the cost of ordinary tricone bits.


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Basic Mud Logging 7. Power system: On a diesel engine rig, diesel engines, which on land rigs are usually located at ground level some distance away from the rig floor, drive large electric generators. The generators, in turn, produce electricity that is sent through cables to electric switches and control gears. From here, electricity goes through additional cables to electric motors that are attached directly to the equipment involved in drilling draw works, mud pumps, and the rotary. The diesel-electric system has a number of advantages over the mechanical system. One of the primary advantages is the elimination of the heavy, complicated compound and chain drive, thus eliminating the need for aligning the compound with the engines and draw works. Another advantage is that the engines can be placed away from the rig floor reducing engine noise for the crew.

8. Mud circulating systems: The drilling fluid (mud) is of great importance to the drilling operation. Whilst drilling, the mud is constantly circulated from the active pits, down through the drill string through the bit, returning up the annulus and back over the shale shaker before returning to the mud pits. The main purposes of circulation are: 1. Transport bit cuttings to the surface. 2. Clean the bottom of the hole. 3. Cool and lubricate the bit and drill string. 4. Support the walls of the wellbore. 5. Prevent entry of formation fluids into the well. Other purposes of circulation are to make it possible to detect gas, oil, or water that may enter the drilling fluid from a formation being drilled; to get information necessary for evaluating producing zones (from cuttings, cores, or electric logs); and to transmit hydraulic power to the bit. In addition, drilling fluid is sometimes used to drive a mud motor that has been placed at the bottom of the drill string. In this case, the drilling fluid provides power to the motor so that the bit turns without engaging the rotary table. Circulating, or drilling fluid is a liquid, it is made up mostly of water, although occasionally oil is the major component. Both types of drilling fluids are called muds, or drilling muds, because that is what they appear to be. Nevertheless, some drilling muds are quite a bit more than just muds; literally, scores of special chemical additives and weighting materials are put into them in order to achieve their purpose with the greatest efficiency. Special clays are used to give body to the mud, and barite (a heavy mineral) is added to increase the density of the mud. Chemicals are used to control the thickness or viscosity of the mud and to improve the ability of the solid particles in the mud to deposit a layer, or cake, on the wall of the hole.


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Basic Mud Logging  Mud pumps: The mud is mixed in the mud pits (sometimes called mud tanks) with the help of a mud hopper into which most of the dry ingredients for the mud are poured. The tanks contain agitators (paddle-like projections) that mix the mud. The mud is mixed with either oil or water, depending on the mud properties needed. The mud pump is the primary component of any fluid circulating system. Pumps are either powered by electric motors attached directly to them, or driven by the compound. The pumps for rotary drilling rigs have high ratings and are capable of moving large volumes of fluid at very high pressures. Mud pumps are generally classified into two main types:

•

Triplex pumps:

Triplex pumps are found now almost universally on new rigs because of their better performance. The triplex pump has three pump cylinders operating on one crank shaft with 120 degree phase difference. Every cylinder pumps with the forward moving action of the piston and recharges with the retracting action of the piston. The cylinder liner and the piston of the mud pump can be changed to provide different balances between volume and pressure. It is not uncommon to operate the pumps with 7” liner during the upper portion of a hole, where large mud volumes are required and then change to 6” liner for the deeper portion of the hole, where volume is less important than pressure.

Triplex mud pump


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Basic Mud Logging •

Duplex pumps:

Duplex pump has two cylinders operating on one crank shaft with 180 degrees. Each cylinder has two suction and two discharge valves. As the piston moves through the cylinder it is discharging mud in front at the same time as mud is filling the cylinder behind. Similar to triplex pump the cylinder liner and the piston of the mud pump can be changed to provide different balances between volume and pressure. It is not uncommon to operate the pumps with 7” liner during the upper portion of a hole, where large mud volumes are required and then change to 6” liner for the deeper portion of the hole, where volume is less important than pressure.

Duplex mud pump PetroServices GmbH Training Center

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Basic Mud Logging  Shale shaker: Shale shaker is a vibrating screen used to separate the drilled solids from the drilling fluid. The screen is mounted on a spring or rubber supported chassis, which is vibrated by means of an eccentric rotating shaft. Screens of different mesh size are available. Mesh sizes being measured by the number of openings per square inch. The screens are sometimes mounted as a pair, using screens of different sizes. In double deck Shaker; mud returning from the well core comes down the flow line and into a surge tank; sometimes known as the possum belly or shaker header box; this allows a smooth flow of mud onto the screens. The shakers are usually situated over a sand trap, which is a narrow pit with sloping sides terminating in a valve, it is used to trap fine sand that may pass through the shaker screens, and this pit must be dumped out periodically.

 Desanders and desilters: These devices remove particles from mud, which were not removed by the shakers or the sand trap. This separation is accomplished by utilizing centrifugal force. The equipment is essentially a series of cones mounted on a manifold; mud is pumped into the manifold and enters the cone. The mud swirls round the inside of each cone, this rotating action causes the lighter fluids to come to one centre and rise out of a hole in the top, whereas the heavier soils go to the outside of the cone and sink down it and out of an opening in the bottom. These units are operated at low pressure (30-40 psi) but can handle high volumes, typically 250 gallons per minute per cone. The difference between desanders and desilters is mainly in the size of the cones. The smaller the cones the smaller the particles that it separates.


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Basic Mud Logging  Mud degasser: When wells are drilled into the earth, it occasionally happens that a quantity of natural gas in a formation penetrated by the well bore becomes entrained in the drilling mud thereby reducing the density of the drilling mud and consequently reducing the hydrostatic pressure of the mud in the well bore. When the hydrostatic pressure decreases, gas from any gas bearing formation is more likely to flow into the well bore thereby further cutting the mud and further reducing its density and hydrostatic pressure if this process continues, the mud will become so light that the well blows out. Consequently, mud degassing units have long been employed in the drilling of wells in areas containing high pressure gas formations that act to remove a great deal of the entrained gas from drilling mud. Commercially available mud degassers fall into a variety of types that operate on a variety of different principles. A typical degasser operates on a vacuum principle. The mud is delivered to a vacuum chamber and spread out in relatively thin sheets over a plurality of downwardly inclined plates or leaves. The idea is that when the mud is spread out, and the vacuum is applied to the chamber, the entrained gas comes out of the mud, is picked up by the vacuum pump and discharged from the vacuum chamber. Other types of mud degassers incorporate pumps that pump the gas saturated mud into separating vessels arranged, in some fashion, to separate the entrained gas from the liquid mud. One of the major defects of standard vacuum degassers and those which pump gas cut drilling mud, is that they are arranged to remove mud from the mud tank, degas the mud and then return the mud to the mud tank. The ideal location to degas drilling mud is before it reaches the mud tank because all of the mud in the system can thereby be degassed and there is no dilution of degassed mud with gas saturated mud. The problem is that commercially available degassers operating on the principles they use are incapable of tolerating the drilled solids, which are carried by the mud. One would appreciate that sand grains, bits of shale or limestone pieces are not readily tolerated by those degassers, which use pump to pump the mud into a separating mechanism. Likewise, a conventional vacuum degasser is rapidly filled up with drilled solids because of the small tolerances and gaps inherent in these mechanisms.


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Basic Mud Logging 9. Blowout prevention system: Blowout preventers (BOPs) are used to control blowout. The crew usually installs several blowout preventers (BOP stack) on top of the well, with an annular blowout preventer at the top and at least one pipe ram and one blind ram blowout preventer below. Also, some well control techniques require both the annular and the ram blowout preventers. An annular blowout preventer has a rubber sealing element that, when activated, seals the annulus between the kelly, the drill pipe, or the drill collar. If no part of the drill stem is in the hole, the annular blowout preventer closes on the open hole. Ram blowout preventers are large steel rams that have sealing elements. One type of ram blowout preventer is called a pipe ram because it closes on the drill pipe; it cannot seal on open hole. Blind ram blowout preventers are straight-edged rams used to close an open hole. Since BOPs are critically important to the safety of the crew, the rig and the wellbore itself, BOPs are inspected, tested and refurbished at regular intervals determined by a combination of risk assessment, local practice, well type and legal requirements. BOP tests vary from daily function testing on critical wells to monthly or less frequent testing on wells thought to have low probability of well control problems.

Blowout preventer stack PetroServices GmbH Training Center

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Basic Mud Logging 10. Special rig components for floating rigs: A mobile floating rig such as the semisubmersible or drillship is constantly being subjected to vertical and horizontal motions due to wind, waves and currents. The rig must be equipped with a system that automatically compensates for these forces. A marine riser system provides for a flexible path for drilling fluids between the drill floor and the wellbore on the below the sea floor. It also provides a passageway for the drill string and casing down to the BOP stack sitting on the sea floor.  Riser system: The drilling riser system consists of a BOP stack hydraulic connection, lower ball joint, flexible choke and kill lines, riser pipe and connectors, telescopic (slip) joints, diverter system, and a riser tensioner system. Some systems include another annular BOP between the hydraulic connector and the lower ball joint. This preventer can be used to allow replacement of the rubber elements on the other annular BOP in the preventer stack.

 BOP stacks: As with all drilling rigs, the offshore rigs are equipped with BOP stacks. The mobile rigs will have the stack mounted on the sea floor below the marine riser. Drilling platforms and jackup rigs will have the BOP stack located in the substructure below the rig floor. The subsea blowout preventers must not only control high pressure formation fluids. They must also be able to close the top of the borehole at the sea floor; disconnect, hang off or cut the drill pipe; and disconnect and reconnect the marine riser system to the wellhead. Modern rigs use single stacks consisting of two annular and four ram-type BOPs in one stack. The total stack may have an 18 ¾-inch bore and 10000-psi or higher working pressure. One ram will contain shear/blind ram blocks for cutting the drill string in case of emergency. PetroServices GmbH Training Center

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Basic Mud Logging  Drill string compensation: The entire drilling rig will heave vertically due to the wave action. The rising deck would pull the entire drill string upward, raising the bit off bottom. As the wave crest passes, the deck would sink rapidly. The rigid drill string would drop and jar the bit on the bottom of the borehole. In addition, the proper amount of weight on bit could not be maintained. Drilling would be impossible and unsafe. The drill string compensation system consists of large cylinders and an air pressure vessel. The cylinders and pistons are placed between the traveling block and the hook suspended in the mast. They are generally capable of stroking 18 feet that is adequate for even high waves. The heave of the drilling rig raises and lowers the fixed portion of the compensator but the relative position of the drill string will remain constant.


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Basic Mud Logging

RIG PERSONNEL Whatever job you perform for PetroServices, you will need to know how the drilling process is managed, supervised and completed. Who is in charge? Who can authorize the stopping of drilling? Who can authorize you to visit the rig floor? The chain of command is usually filled with personnel of varying degrees of experience. Those at the top have generally had experience in all phases of rig operations. Those with the least experience are usually found performing specific duties requiring limited training. The drilling bid proposal will contain many important specifications. These will usually include the starting date, depth to be drilled (TD), formations to be penetrated, hole sizes, casing sizes, drilling mud program, logging program, casing program, cementing, testing and well completion. A company representative represents the operating company on the rig site.

 Company representative. The company representative is employed by the operating company, and is responsible for all phases of drilling the well and for all needed equipment and services such as casing, drilling mud, logging and cementing. Upon arrival at a rig site, contact the company representative first.  Tool pusher. The tool pusher is in charge of the drilling rig and crews needed in the drilling operations. He is generally an expert in drilling operations and equipment, and is the main liaison between the drilling contractor and the operating company.  Driller. The next highest level of authority on the rig is the driller, who is the working supervisor for the shift. The driller operates the controls on the drill floor. He raises and lowers the drill string, sets the speed and penetration rates, operates the mud pumps and operates the BOP stack as needed. The driller reports to the tool pusher.  Derrick man. The next man in line under the driller is the derrick man. He is experienced enough to assist or relieve the driller. During a trip out of the hole, he will work in the derrick racking the stands of drill pipe. At other times, he may be servicing the mud and mud equipment.  Roughnecks. The roughnecks are the workers who make up and break out the joints of pipe. They work on the floor and keep a steady supply of drill pipe to connect to the drill string. The roughnecks also help maintain other equipment on the rig floor. The roughnecks report to the driller. While drilling, one Roughneck is present in the mud process room at all times. He takes mud weights and ensures shakers and other machines are working properly.  Crane operator. The crane operator is in charge of the loading and unloading of boats. The pipe rack area is also in crane operator’s charge, as are the roustabout crews. The crane operator reports directly to the tool pusher.  Roustabouts. The roustabouts are the workers who help load and unload equipment for the crane operator. They also clean, repair and maintain the rig and its systems. They report to the crane operator.  Subsea engineer. The subsea engineer is responsible for maintaining the subsea blowout prevention system. This includes the wellhead connection, the BOP stack, control system, marine riser system and the motion compensation equipment. PetroServices GmbH Training Center

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Basic Mud Logging  Barge engineer. A floating platform and drillship will have a barge engineer assigned, who is responsible for the stability and ballast of the vessel. The barge engineer must be notified before any heavy equipment is moved or loaded on the rig. He must keep the rotary table in the correct position to drill the hole.  Specialty crewmen. Some skills are needed on the rig full time. These specialty skills include the motorman, rig mechanic, rig welder, and rig electrician.  Service specialists. The operator will contract with special service companies for certain needs. These service crews include well loggers, mud suppliers, analysis and treatment, cementing, casing, wireline operations and others.  Motorman. The motorman is responsible for maintenance of the engines. While all members of the rig crew help with major repairs, the motorman does routine preventive maintenance and minor repairs.


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Basic Mud Logging

DRILLING FLUIDS PROPERTIES Definition of a drilling fluid according to API is “a circulating fluid used in rotary drilling to perform any or all of the various functions required in the drilling operation”. The functions of drilling fluids are quit complex and the success of a drilling program depends on the proper understanding and application of these functions. The following functions are the most important functions of drilling fluids during drilling operations.

 Cooling the bit and lubricating the drill string: During drilling, considerable heat and friction is built up due to bit contact with the formation. The heat buildup by the continual friction is transmitted to the drilling fluid and circulated to the surface where it is dissipated. The drilling fluid also lubricates the bit by reducing the friction factor of the formation on the bit and drill string. Since most drilling fluids contains additives (i.e. bentonite, polymers) which help reduce the downhole friction, further lubricants need not to be used unless warranted by difficult and unusual conditions such as sever doglegs or high torque. Unless a bit is well cooled, it overheats and quickly wears out. Fluid circulated around the parts of the bit removes the heat. Oily substances in the drilling fluid can reduce friction in the bit bearings and act as a lubricant between the drill string and the walls of the hole. Oil-emulsion mud and oil base mud are especially helpful in this way.

 Transmitting hydraulic horsepower to the bit: The drilling fluid is the medium through which hydraulic horsepower is transmitted to the bit. A viscoelastic drilling fluid, that is a drilling fluid whose viscosity at the bit approaches the viscosity of water, will minimize the friction losses and maximize the available hydraulic horsepower at the bit. Fluid flowing from the bit nozzles exerts a jetting action that keeps the face of the hole and the teeth edge of the bit clear of the cuttings. The horsepower required to move the mud through the remaining system should be minimized in order to maximize horsepower at the bit. The heavier a fluid becomes, the greater the horsepower that is required to move it through the system. This results in less horsepower at the bit and slower penetration rates. Hydraulic energy can be used to maximize the rate of penetration by improving cuttings removal at the bit. It also provides power for mud motors to rotate the bit. Hydraulic energy is measured in terms of hydraulic horsepower.

 Cleaning the bottom of the hole: This function of the drilling fluid is essential to achieve the optimum penetration rate with a given bit, weight, rotary speed and hydraulic program. A properly designed hydraulics program should provide an adequate flow rate to create a sufficient cross flow across the bottom of the bit to instantaneously lift the cutting being drilled up. Otherwise, penetration rate will be retarded due to regrinding of the cuttings by the bit. The usual method for cleaning the hole is by circulation of fluids through jet nozzles in the bit. High-velocity streams of fluid blast the bottom of the hole, creating a turbulence that moves the chips from the face of the formation as fast as they are formed.


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Basic Mud Logging  Removing cuttings: Removal of cutting from the hole is a vital function of the drilling fluid. This function is primarily dependent on the annular velocity profile and not strictly on the average annular velocity as commonly assumed. The annular velocity profile, in turn will depend on both the average fluid velocity and the viscosity (mainly yield value) of the mud. The yield value can be controlled by drilling fluid additives and should be maintained at the minimum value required for optimum solids removal from the hole. Precise control of the gel strengths of the mud is also important to suspend the cuttings when circulation is stopped. The required yield value and gel strengths will depend on the type of drilling fluid in use and should be adjusted as dictated by the hole conditions in a given drilling area.

 Supporting the walls of the well: A drilling fluid with the proper characteristics can support a formation that might otherwise cave in. This type of drilling fluid, or mud, plasters the walls of a well like mortar. Furthermore, the hydrostatic pressure created by the weight of the fluid column in the hole pushes against the plastered wall to support unconsolidated or loose formations that might fall or slough into the hole. Hard rock formations have little tendency to slough and can therefore be drilled with air, gas or water instead of mud. Filter cake, the plaster-like coating formed from mud solids on the walls of a well, has the ability to seal the wellbore and prevent the loss of whole fluid. The force of the hydrostatic pressure squeezes the liquid part of the mud (the filtrate) into the permeable zones (such as sand), and the solid material is left behind as a filter cake.

 Controlling formation pressures: The drilling fluid density should be adequate to contain any formation pressures encountered to prevent the influx of formation fluids or gases into the wellbore and provide a safety margin while tripping pipe. However, it must not be so high as to create excessive differential pressures, which will impede drilling rate and may cause lost circulation and differential sticking. Water or mud produces sufficient hydrostatic head to overcome formation pressures usually encountered. The addition of weighting material to mud being circulated in a well can make a mud dense enough to hold back almost any formation pressure. When formation pressures are expected to be high, a high mud weight is needed, so the pits and other equipment should be arranged to handle the heavy mud. A mud weight of 16 to 18 ppg is considered heavy.

 Transporting cuttings to the surface: Drilling fluids in circulation moves rock chips, sand, or shale particles out of a well as it moves up the annulus. The drilling fluid velocity in the annulus is usually from 100 to 300 feet per minute (ft/min) in order to keep the hole clean. The solids in mud are separated at the surface by screening, settling, centrifugal action, chemical flocculation, or a combination of methods. Solids brought up by air or gas in air drilling are blown as dust or fine chips to a waste pit. Yield value and gel strengths, which affect the suspension and removal of the drilling solids from the wellbore, also affect the efficiency of the solids removal techniques at the surface. These properties are controlled by the colloid fraction of the drilling fluid and must be sufficient to suspend and remove cuttings from the wellbore, yet low enough to release the cuttings at the surface.


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Basic Mud Logging Drilling fluid types: Many types of drilling fluids are used on a day to day basis. Some wells require that different types be used at different parts in the hole, or that some types be used in combination with others. The various types of fluid generally fall into a few broad categories:  Water: Water by itself is pumped to do very specific things in very specific formations.  Water-based mud (WBM): A most basic water-based mud system begins with water, then clays and other chemicals are incorporated into the water to create a homogenous blend resembling something between chocolate milk and malt (depending on viscosity). The clay (called "shale" in its rock form) is usually a combination of native clays that are dissolved into the fluid while drilling, or specific types of clay that are processed and sold as additives for the WBM system. The most common of these is bentonite, frequently referred to in the oilfield as "gel". Gel likely makes reference to the fact that while the fluid is being pumped, it can be very thin and free-flowing (like chocolate milk), though when pumping is stopped, the static fluid builds a "gel" structure that resists flow. When an adequate pumping force is applied to "break the gel", flow resumes and the fluid returns to its previously free-flowing state. Many other chemicals (e.g. potassium formate) are added to a WBM system to achieve various effects, including: viscosity control, shale stability, enhance drilling rate of penetration, cooling and lubricating of equipment.  Oil-based mud (OBM): Oil-based mud can be a mud where the base fluid is a petroleum product such as diesel fuel. Oil-based muds are used for many reasons, some being increased lubricity, enhanced shale inhibition, and greater cleaning abilities with less viscosity. Oil-based muds also withstand greater heat without breaking down. The use of oil-based muds has special considerations. These include cost and environmental considerations.  Synthetic-based fluid (SBM): Synthetic-based fluid is a mud where the base fluid is a synthetic oil. This is most often used on offshore rigs because it has the properties of an oil-based mud, but the toxicity of the fluid fumes are much less than an oil-based fluid. This is important when men work with the fluid in an enclosed space such as an offshore drilling rig.

Mixing drilling mud: Attention should be given to the equipment used to mix drilling mud’s and to the sequence of addition of the mud and any additives. • • • • • • •

If the make up water requires treatment, always treat it prior to addition of the bentonite clay. Use a jet hopper mixer to disperse the bentonite clay. Bentonite clay (Super Gel-X) should be mixed slowly through the jet hopper at a rate of one 50 lb. bag every 10 to 20 minutes. Volume of mud pit should be three times the volume of the proposed hole. Figuring volume of pit length (ft.) x width (ft.) x depth (ft.) x 7.5 = volume (gal). The mud pit should be of such design that the drilling mud, during flow, changes direction and slows, allowing for cuttings to drop out. The addition of viscosifying polymers should be made after the bentonite clay mud is thoroughly mixed in fresh water. Viscosity and density tests should be run on the drilling mud following mixing. Periodic tests should be made during drilling and changes noted. Sand content tests should be run on the mud once drilling starts.


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Basic Mud Logging Mud properties terminology: Various properties of the mud are measured as an indication of the performance of the mud in the hole. Tests commonly made are:

1. Mud weight (density): Mud weight is a density measurement expressed in terms of the weight of a unit volume of the drilling fluid. Ideally, a mud weight as low as the weight of water is desired for achieving optimum penetration rates and for minimizing the chances of loss of circulation. However, in reality, mud weight as high as two and one-half times the weight of water may be necessitated to prevent or control a “well kick” or “hold back” troublesome formations. As a rule, to achieve the optimum penetration rate with safety, the mud weight should be kept at a minimum value that will balance the formation pressures and provide a slight overbalance to insure safety against swabbing the well during connections or trips. As is with other mud properties, the ability to effectively control the mud weight is directly related to the capability of controlling the nature and content of all solids in a drilling fluid. The mud weight may be determined using any instrument that will permit accurate measurement within 1/10 lb/gal or ½ lb/cu. ft. The mud balance is the instrument generally used. Mud weight can be expressed in lb/gal, lb/cu. ft., and psi/1000 ft. of depth or specific gravity (S.G.).

Procedure: 1. Fill the cup with the mud to be weighed. 2. Place the lid on the cup and seat it firmly but slowly with a twisting motion. Be sure some mud runs out of the hole in the cap. 3. With the hole in the cap covered with a finger, wash or wipe all mud from the outside of the cup and arm. 4. Set the knife on the fulcrum and move the sliding weight along the graduated arm until the cup and arm are balanced. 5. Read the density of the mud at the left-hand edge of the sliding weight. 6. Report the result to the nearest scale division in lb/gal, lb/cu ft, S.G., or psi/1000 ft of depth. 7. Wash the mud from the cup immediately after each use. It is essential that all parts of the mud balance be kept clean if accurate results are to be obtained. 8. Refer to Table 1 for conversion data if not available on balance. Calibration: The mud balance should be calibrated frequently with fresh water. Fresh water at 70º F will give a reading of 8.33 lb/gal or 62.3 lbs/cu ft. To adjust the mud balance to the proper reading, add or remove lead shot from end of balance arm or adjust set screw at the end of the balance arm.


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Basic Mud Logging 2. Mud viscosity: Qualitatively, viscosity is defined as “the internal resistance of a fluid to flow”; the drilling fluid viscosity can be expressed as either relative or absolute measurements. The relative measurements are the funnel viscosity and the qualitative viscosity. The absolute measurements are the quantitative values of the non-Newtonian characteristics, namely, the plastic viscosity, the yield point and gel strengths.

 Funnel viscosity: The Marsh Funnel Viscosity is the ratio of the speed of the mud as it passes through the outlet tube (the Shear Rate) to the amount of force - the weight of the mud itself - that is causing the mud to flow (the Shear Stress). Marsh Funnel Viscosity is reported as the number of seconds required for one quart of mud to flow out of a full Marsh Funnel. Procedures: 1. Collect a fresh mud sample. 2. Hold the funnel erect with a finger over the outlet tube, and pour the mud into the funnel through the screen until the mud level reaches the bottom of the screen (The screen will filter out the larger particles that could clog the outlet tube). 3. Quickly remove the finger from the outlet tube, and at the same time, begin timing the mud outflow. 4. Allow one quart (946 cc) of mud to drain from the Marsh Funnel into a graduated container. 5. Record the number of seconds it takes for the quart of mud to flow out of the funnel, and report this value as the Marsh Funnel Viscosity. Also, record the temperature of the mud sample in degrees F or C. Care of the funnel: Follow these suggestions to care for the Marsh Funnel: 1. Clean and dry the funnel thoroughly after each use. 2. Take special care not to bend or flatten the brass outlet tube at the bottom of the funnel. The Marsh Funnel Viscosity readings are computed using the exact diameter of this outlet and if the outlet is distorted the readings will be inaccurate.

Calibration check: Periodically check the calibration of the Marsh Funnel by measuring the viscosity of fresh water. The funnel is dimensioned so that the outflow of one quart (946 cc) of fresh water at a temperature of 70‘±5‘F (21‘±3‘C) is 26±0.5 seconds. If the Marsh Funnel checks out of calibration, it should be cleaned again, using a pipe cleaner, to make sure that there is nothing obstructing the outlet. If the Marsh Funnel continues to give an incorrect reading for fresh water after cleaning then the outlet tube probably has been bent out of shape and the funnel should be replaced.


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Basic Mud Logging  Plastic viscosity: In term of physical relationships, the plastic viscosity is the part of the flow resistance of the fluid caused by mechanical friction within the fluid. This mechanical friction is due to the interaction of solid particles in the mud, the interaction of solid and liquid particles, and the deformation of the liquid particles under a shear stress. The interaction between the solid particles and between the solid and liquid particles will in turn depend on the type and nature of the particles, the number of particles, the size of particles, the shape of particles and the state of particles present in mud. Even though the plastic viscosity cannot be calculated or determined exactly based on a given concentration of solids, the observed value of the plastic viscosity will be a qualitative indication of the solid contents of a drilling fluid. Plastic viscosity is defined as the 600-RPM shear stress reading minus the 300-RPM shear stress reading.

Rotational viscometers

 Yield point: The yield point is physically the measurement of the electrochemical forces within the mud under flowing conditions. These electrochemical forces are due to the charges on the surface of reactive particles, the charges on the sub-micron size particles, and the presence of the electrolytes in water phase. The yield value is the dominant factor that affects the circulating friction losses, the equivalent circulating density, the transition point into turbulent flow, and the carrying capacity of a drilling fluid. Yield point is defined as the 300-RPM shear stress reading minus the plastic viscosity. Yield point is a measure of the attractive forces between active clay particles in the mud under flowing conditions. When the mud is at rest, the solid particles tend to arrange themselves in such a manner that these attractive and repulsive forces are best satisfies. It is also a measure of the hole cleaning capabilities of a mud.


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Basic Mud Logging 3. Gel strengths: Gel Strength is a measure of the attractive forces of suspended particles in a liquid when that liquid is in a static state. Gel strength is reported in lb/100 sq ft. The gel strength influences the surge and swabbing effects of the drilling fluids when trapping the drill string, the pressure required to break circulation, ease of release of gas, and setting of suspended particles in the pits. Relative measures of gel strength properties are made on a direct indicating viscometer and are commonly reported as 10 sec and 10 min. gels. Drilling mud has gel strength when a force is required to start the mud moving. Gel strength arises mainly from attraction between particles and from friction between solids in suspension or between the solids and the liquid around them.

4. Filtration: Filtration test is a relative measure of liquid filtered into a permeable formation and of the cake left on the formation. The condition of the mud and type of solids in the mud influence filtration. There are two standard filtration tests. One is at ambient temperature and 100 psi and the other at 300°F and 500 psi. The high temperature – high pressure test should preferably be run under actual bottom hole temperatures and differential pressures existing in the well bore. Filtration is dependent upon the amount and physical state of the colloidal material in the mud. It has been shown repeatedly in the field that when the mud of sufficient colloidal content is used, drilling difficulties are minimized. In contrast, a mud low in colloids and high inert solids, deposit a thick filter cake on the walls of the hole. A thick filter cake restricts the passage of tools and allows an excessive amount of filtrate to pass into the formation, thus providing a potential cause of caving. Lack of proper walling properties may result in further trouble such as difficulty in running casing, creating a swabbing effect, which may cause the formation to cave or swab reservoir contents into the hole, and difficulty in securing a water shutoff because of channelling of cement.

5. Fluid loss: The fluid loss properties of a drilling fluid have a direct bearing on the penetration rate, hole problems in areas of sloughing shales, formation damage in sensitive reservoirs, and differential sticking problems in permeable zones. Since the drilling fluid in a borehole can either be in a dynamic state (while drilling) or in a static state (while tripping), the fluid loss into formation occurs under both dynamic and static conditions. Static fluid loss is by definition the steady state fluid loss into a permeable formation through a filter medium (mud cake). This static fluid loss rate is described and governed by Darcy’s law of fluid flow through porous medium, modified to include the effects of filtration through the mud cake. The dynamic fluid loss will differ according to the flow regime (laminar or turbulent) in existence. Under laminar flow conditions across a permeable zone, the dynamic fluid loss will behave essentially similar to the static fluid loss but will be slightly higher since the buildup of the mud cake will be somewhat retarded. If the flow regime is in turbulent flow, the mud cake will be simultaneously eroded as it is being deposited at a rate, which cannot be predicted precisely. Whether the flow regime is laminar or turbulent, predicting the dynamic fluid loss is further complicated by the action of the drill string eroding and plastering the mud cake in the wellbore.


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Basic Mud Logging 6. Sand content: The solids in suspension in a drilling fluid are in essence the “blood cells” which make up that circulating system. Certain types of solids, in proper concentrations, are essential in formulating and maintaining the desired properties to achieve the drilling fluid system at the surface in controlled amounts. The nature of the drilled solids which can be retained in suspension by a drilling fluid can vary from reactive bentonitic particles to inert sand grains. These particles either hydrate and disperse into the drilling fluid unless mechanically or chemically surpressed from doing so or will be ground down to a very fine size and become a colloidal suspension if not separated from the drilling fluid the first time they are circulated to the surface. Sand content is the volume percentage of particles larger than 74 microns. Periodic determination of the sand content in a drilling fluid is desirable. Excessive sand may result in the deposition of a thick filter cake on the wall of the borehole, in turn it may settle in the hole around the tools when circulation is stopped and may cause interference with the successful operation of drilling or when the casing is set. High sand content also causes excessive abrasion of pump parts and pipe connections. Sieve analysis is the preferred method for sand content determination because of the reliability of the test and simplicity of equipment. The volume of sand, including that of void spaces between grains, is usually measured and expressed as a percentage by volume of the drilling fluid. The sand content of a drilling fluid is measured by means of FANN sand content kit, which is a simple, accurate and inexpensive sieve analysis apparatus for determining the sand content of drilling mud. The kit consists of a special 200-mesh sieve 2-1/2" in diameter, fastened inside a collar upon either end of which fits a small funnel. This is used with the sand content tube. The collar and funnel are made of polyethylene and the screen is made of brass.

Sand content kit PetroServices GmbH Training Center

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Basic Mud Logging 7. Drilling fluid pH: The degree of acidity or alkalinity of drilling mud is indicated by the hydrogen-ion concentration, which is commonly expressed in terms of pH. A perfectly neutral solution has a pH of 7.0. Alkalinity solutions have pH readings ranging from just above 7 for slight alkalinity to 14 for the strongest alkalinity, while acid solutions range from just below 7 for slight acidity to less than 1 for the strongest acidity. The pH measurement is used as an aid in determining the need for chemical control of mud as well as indicating the presence of contaminates such as cement or gypsum. There are two common methods of obtaining this value. The pHydroin dispenser, which provides a series of paper indicator strips that determine pH from 1 to 14. Changes in color or color identity over the range of each indicator should be sufficient to allow the operator to read within 0.5 pH units. pHydroin dispenser The other method is the pH meter. The meter will measure the pH within 0.1 pH units. The pH meter calculates a value by measuring the voltage differences between the pH electrode (responsive to hydronium ion concentration) and the reference electrode (which provides a constant voltage). The meter must be calibrated in order to compensate for the difference in voltage output from different electrodes. It is recommended that at least two buffer solutions be used to calibrate the machine.

Digital pH meter

pH measuring principle

8. Alkalinity: A dictionary description of alkalinity is water soluble chemicals that can neutralize acids. There are three tests for alkalinity, which are Pm, Pf, and Mf. Pf and Mf is the alkalinity of the filtrate. Pf is the amount in milliliters of N50 sulfuric acid required to reduce the pH of one ml of filtrate to 8.3 Mf is equal to the Pf and ml of N50 sulfuric acid required to reduce the pH from 8.3 to 4.3. With the use of these tests, one can determine the type contaminate present in the mud.


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Basic Mud Logging 9. Chloride content: It is desirable to know the salt content of muds to account for certain aspects of their performance. Filtration, suspension, viscosity and gel properties are adversely affected by salt unless the mud is specifically designed to withstand salt contamination. Salt content determination made at regular intervals may be useful in identifying salt sections or filtration of salt water into the mud system. The salt content in the sample is expressed in parts per million chlorides (ppm Cl). The salinity of the drilling fluid is determined by titrating the filtrate for total chlorides. It is commonly assumed that all of the chlorides are due to the presence of common salt (NaCl) and the chloride content converted to salt content or vice versa by the following conversions: ppm Salt (NaCl) = ppm Chloride (Cl-) x 1.65 ppm Chloride (Cl-) = ppm Salt (NaCl) x 1.65 The maximum chloride saturation in water at 20o C (68o F) is 188,000 ppm. This is equivalent to maximum saturation of 311,000 ppm salt (NaCl).

10. Total hardness (calcium content): The total hardness of a solution is the sum total of the calcium and magnesium ions in that solution. Commonly and erroneously, the total hardness of the filtrate is reported as the calcium content. The separate concentrations of Ca++ can be determined by first titrating for the total hardness using the Calmagite indicator with the total hardness buffer solution and then titrating specifically for the Ca++ ion using Calver II buffer and indicator solutions. The difference between the total hardness and Ca++ content will be the concentration of the Mg++ ions. In the control and maintenance of a drilling mud, it may be desirable to determine the presence and quantity of calcium ion. Calcium ions may be added to the system by drilling cement, anhydrite or gypsum, or by the addition of hard make-up water and treating chemicals containing calcium, etc. If the source of the calcium ions is the make-up water or gypsum stringers, the calcium can be precipitated with soda ash. The chemical reaction is shown below: CaSO4 (Gypsum)

+

Na2CO3 (Soda Ash)

Na2SO4 (Soluble)

+

CaCO3 (Precipitated)

If the calcium ions are due to cement contamination, sodium bicarbonate (NaHCO3) should be instead of soda ash to treat out cement contamination, especially in non dispersed systems where acids cannot be utilized. The chemical reaction is shown below: Ca(OH)2 (Cement)

+

NaHCO3 (Bicarbonate)

H2O (Water)

+

CaCO3 (Precipitated)

The magnesium ions are precipitated by the use of caustic soda in the same concentration as soda ash in treating calcium. The chemical reaction is shown below: MgSO4 (Epsom Salt)

+

2 NaOH (Costic Soda)


Na2SO4 (Soluble)

+

Mg(OH)2 (Precipitated)

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Basic Mud Logging

DRILLING PROCESS Drilling for oil and gas seems, on the surface, to be a relatively simple process of drilling a subsurface hole (wellbore) until it penetrates an oil or gas-bearing formation. However, in reality, drilling for oil or gas is a highly sophisticated process requiring an effective organization; a vast knowledge base, large amounts of capital, expensive equipment and machines, and dedicated, highly trained and committed personnel. In order to begin to understand the process, it is important to become familiar with a number of generalizations that can be made about drilling an oil or gas well. The drilling process includes different operation that takes place on the rig site such as drilling, tripping, casing run, cementing, wireline logging and perforating in addition to some drilling problems that might arises such as stuck pipe and loss of circulation.

1. Drilling: The well is created by drilling a hole 5 to 36 inches (127.0 mm to 914.4 mm) diameter into the earth with a drilling rig which rotates a drill string with a bit attached. After the hole is drilled, sections of steel pipe (casing), slightly smaller in diameter than the borehole, are placed in the hole. Cement may be placed between the outside of the casing and the borehole. The casing provides structural integrity to the newly drilled wellbore in addition to isolating potentially dangerous high pressure zones from each other and from the surface.

 Vertical drilling: First about 20 to 100 feet has to be drilled and lined with conductor pipe. The diameter of the conductor pipe varies according to hole size. Conductor or surface pipe can be hammered driven or a borehole made to lower the conductor into and cement the pipe in place. A casing head is fixed to the top of the conductor at the surface. A bit with smaller size than the internal diameter of the conductor pipe is to be chosen. The selected bit is then made up on the end of the first drill collar and both bit and drill collars are lowered into the conductor hole. Enough collars and drill pipe are made up and lowered in until the bit is almost to bottom. The kelly is then picked up out of the rat hole where it has been stored and is made up on the topmost joint of drill pipe sticking up out of the rotary table. This joint of pipe is suspended in the rotary table by the slips. With the kelly made up, the pump started to begin circulating drilling mud and the kelly bushing in the rotary table and rotation begins. Next, the driller gradually releases the draw works brake and the rotating bit touches bottom and begins “making hole”. Using an instrument called the weight indicator, the driller monitors the amount on weight put on the bit, since the kelly is about 40 feet long, after 40 feet of hole is made the driller stops the rotary, stops the pumps and raises the kelly exposing the top of the previously connected joint. The drilling crew prepares to make the first connection. They set the slips around the joint of pipe and latch a big set of wrenches - called tongs - around the base of the kelly. Tongs pull line - a length of a strong wire rope - runs from the end of the tongs over to the PetroServices GmbH Training Center

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Basic Mud Logging breakout cat-head on the draw works. The driller engages the cat-head and it starts pulling on the line with tremendous force. The pulling force on the tongs breaks out or loosens the threaded joint between the kelly and drill pipe. Once the joint is loosened the crew removes the tongs - and the driller engages the kelly spinner (an air-actuated device mounted permanently near the top of the kelly).The kelly spinner turns or spins the kelly so that it unscrews rapidly from the drill pipe. The crew moves the kelly over to the mouse-hole, which is just a hole in the rig floor lined with pipe into that hole a joint of drill pipe is placed prior to its begin made up in the string. The crew stabs the kelly into the box of the drill pipe and the driller spins the kelly. The crew grabs the tongs, latches them onto the kelly and pipe and bucks up (tightens) the joint to final tightness. (Each pipe size and grade has its own tightening torque range that must never be exceeded by the driller). The driller uses the draw works to raise the kelly and attached joint out of the mousehole. The crew stabs the end of the new joint hanging in the rotary and the two are connected together, the joint is spun up and tongs are used to make them up to final tightness. Finally, the driller lifts up the kelly and attached strings a little, the crew removes the slips and the newly added joint and kelly are lowered until the kelly bushing engages the rotary. What has just been described is called “making connection” and can actually be carried out almost in less time than it takes to tell about it. The pump is started, the bit is set back on bottom and another thirty or so feet are drilled, a connection is made each time the kelly is drilled down i.e. each time about thirty feet of hole is made. The kelly is normally fifteen feet longer than a joint giving room for maneuver. The previous operation is repeated times and times until a desired depth is reached or bit change process is needed.

 Directional drilling: Usually but not always, the crew tries to drill the hole as straight as possible, but at times it is desirable to deflect the hole from vertical. The most dramatic example of this is the offshore platform. Many wells may be drilled from a single platform without having to move the rig. The technique used is called “directional drilling”. Only the first hole drilled into the reservoir tray be vertical; each subsequent well may be drilled vertically to a certain depth then kicked-off (deflected) directionally so that the bottoms of the hole ends up away from its starting point on the surface. By using directional drilling, as many as twenty or more wells may be drilled into the reservoir from one platform. Thus, directional drilling has become a routine development operation throughout the world. The intentional deviation of a wellbore from the path it would naturally take. This is accomplished through the use of whipstocks, bottomhole assembly (BHA) configurations, instruments to measure the path of the wellbore in three-dimensional space, data links to communicate measurements taken downhole to the surface, mud motors and special BHA components and drill bits. PetroServices GmbH Training Center

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Basic Mud Logging While many techniques can accomplish directional drilling, the general concept is simple: point the bit in the direction that one wants to drill. The most common way is using a bend near the bit in a downhole steerable mud motor. The bend points the bit in a direction different from the axis of the wellbore when the entire drill string is not rotating. By pumping mud through the mud motor, the bit turns while the drill string does not rotate, allowing the bit to drill in the direction it points. When a particular wellbore direction is achieved, that direction may be maintained by rotating the entire drill string (including the bent section) so that the bit does not drill in a single direction off the wellbore axis, but instead sweeps around and its net direction coincides with the existing wellbore. Rotary steerable tools allow steering while rotating, usually with higher rates of penetration and ultimately smoother boreholes. Directional wells are drilled for several purposes: • • •

•

Increasing the exposed section length through the reservoir by drilling through the reservoir at an angle. Drilling into the reservoir where vertical access is difficult or not possible. For instance an oilfield under a town, under a lake, or underneath a difficult to drill formation. Allowing more wellheads to be grouped together on one surface location can allow fewer rig moves, less surface area disturbance, and make it easier and cheaper to complete and produce the wells. For instance, on an oil platform or jacket offshore, up to about 40 wells can be grouped together. The wells will fan out from the platform into the reservoir below. This concept is being applied to land wells, allowing multiple subsurface locations to be reached from one pad, reducing environmental impact. Drilling "relief wells" to relieve the pressure of a well producing without restraint (a "blow out"). In this scenario, another well could be drilled starting at a safe distance away from the blow out, but intersecting the troubled wellbore. Then, heavy fluid (kill fluid) is pumped into the relief wellbore to suppress the high pressure in the original wellbore causing the blowout.

2. Coring: A core sample is a cylindrical section of a naturally occurring medium consistent enough to hold a layered structure. Using a special core bit, a solid cylinder of rock, approximately 4” – 5” in diameter and in 30 ft increments, is extracted from a well. Conventional core sampling is generally available over short reservoir sections and is helpful when needing analysis on a detailed scale. The wealth of information available from a conventional core makes it the most accurate fundamental tool available in understanding oil and gas reservoirs.

Diamond core bit PetroServices GmbH Training Center

Core samples Page 46 of 196

Basic Mud Logging  Conventional coring: An assembly called a "core barrel" is made up on the drill string with a special type of bits called “Core Head” and run to the bottom of the hole. As the core barrel is rotated, it cuts a cylindrical core a few inches in diameter that is received in a tube above the core cutting bit. There are many types of core barrel in use as the conventional, the rubber sleeved, the fiberglass, etc. A complete round trip is required for each core taken. After each core was cut, the inner core barrel was laid on the catwalk and the PVC sleeve containing the core was extruded from the barrel and cut into three foot sections. Each section was measured and marked for depth at one-foot intervals. Where applicable, depths were assigned such that any core not recovered was attributed to the bottom of the cored interval. The core sections were boxed and then placed in a truck maintained at 35¡ F. at the wellsite.

 Sidewall coring: A core taken from the side of the borehole, usually by a wireline tool. Sidewall cores may be taken using percussion or mechanical drilling. Percussion cores are taken by firing hollow bullets into the formation. The bullets are attached to the tool by fasteners, and are retrieved, along with the core inside, by pulling up the tool and the fasteners. Percussion coring tools typically hold 20 to 30 bullets, but two or three tools can be combined on one run in the hole. Mechanical tools use hollow rotary drills to cut and then pull out core plugs. Up to 75 plugs can be recovered on one run. With full recovery, cores from typical percussion tools are 1 in. [2.5 cm] in diameter by 1 3/4 in. [4.4 cm] long, while those from mechanical tools are 0.91 in. [2.3 cm] in diameter by 2 in. [5 cm] long. The latter are also known as rotary sidewall cores.

Sidewall core sample


Sidewall coring

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Basic Mud Logging 3. Tripping: After the hole is conditioned for any reason (such as casing, changing the bit, changing the mud motor, changing any part of BHA, or running wire line), all of BHA and drill pipes have to be removed from the hole and stacked against the derrick or mast. Depending on the size of the rig and length of the mast, stands made of two joints or three joints are removed from the hole and are stacked. During this operation, the following must be done:    

Fill the hole with mud as the pipes are being removed from the drill stem. Monitor any increase or decrease in the mud volume removed from the hole or added to the hole. If there is any extra drag (friction to the wall) which is not normal, start circulation and the hole in that section will be cleaned. If there is any discrepancy in the depth, measure and record all of the stands to verify the correct depth.

Tripping operation takes place through the following steps:

 The drill pipe is suspended in the hole and the kelly is disconnected. (Using slips and 

  

   

tongs). The kelly is swung across the rig floor and lowered into the rat hole, and then the swivel is unlatched from the travelling block hook. The rat hole is a tube rather like the mousehole. It provides a storage receptacle for the kelly, kelly bushings and swivel when they are not in use during the round trip. One of the rig crew - the derrick man, climbs to the monkey board high in the derrick. He secures himself at this working platform using a safety harness. It is his job to handle the top of the stand during the round trip. Elevators are latched around the drill pipe just below the tool joint. The elevators are a set of hinged clamps, which are part of the hook and travelling block assembly. They are connected to links which themselves are attached to the eyes of the hook. The driller can now start to pull the drill string out of the hole. As he starts to raise the string, the slips are removed by the roughnecks on the rig floor. The string is then lifted until the third tool joint is clear of the rotary table and the slips are re-set. Now we have a stand of drill pipe up in the derrick being held by the elevators, while the rest of the string is in the hole suspended from the slips. The next job for the roughnecks is to disconnect the stand from the drill string. This is done using the tongs and pipe spinner. The lower end of the stand is then swung to one side of the rig floor and stood down. The derrick man job now is to unlatch the elevators having first secured the top of the stand with a rope. With the stand now clear, he can pull the top of the stand into the fingers of the monkey board. The stand is now racked (stored) in the derrick. The driller now lowers the travelling assembly, allowing the roughnecks to latch the elevators round the next tool joint ready to pull another stand. The procedure, which was just described, is repeated until all the pipes are out of the hole. Depending on the depth of the hole, this could take an entire day to complete.

The drill collars and bit are the last items to come out of the hole. To unscrew the bit from the bit sub, a device called a bit breaker is placed in the rotary table. This piece of equipment holds the bit while the tongs are used to break the connection. We have now seen one-half of a round trip, tripping out. The second half of a round trip is called tripping in and is just the reverse procedure. PetroServices GmbH Training Center

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Basic Mud Logging

Pull out of hole

Stand stood down

Derrick man

Derrick man while running in hole


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Basic Mud Logging 4. Casing: As the drilling of an oil or gas well progresses, it becomes necessary to line the walls of the hole with heavy steel pipe called casing. The casing, together with cement around it performs the following functions: • Prevent caving of the hole. • Prevent contamination of freshwater in the upper sand zones. • Exclude water from the oil or gas producing formations. • Confine production to the wellbore. • Provide a means for controlling pressure. • Facilitate installation of the subsurface equipment required if artificial lift method becomes necessary in producing the well. • Facilitate the use of acidizing, zone fracturing, etc. • Allows segregation of formations behind the pipe and thereby prevents inter-formational flow, and permits production from a specific zone. One or more of the following strings of casing is required in every well:  Conductor pipe: This is needed as a conduit to raise the circulating fluid high enough to return the fluid to the surface pits. It also prevents washing out from around the base of the rig. Holes for the conductor pipe can be drilled in the usual fashion, but the pipe is often driven in with a pile driver (especially in swamps and offshore locations on jackups and fixed platforms). Conductor Pipe usually ranges from 30 to 42 inches in outside diameter offshore, and 16 inches onshore.  Surface casing: This is set deep enough to protect the well from cave-in of loose formations that are encountered near the surface and to isolate the fresh water formations. It is the starting point for the wellhead, and in most cases serves as the base for the B.O.P stack during drilling operations and the “Christmas Tree” if the well is completed for production. An important factor concerning the setting depth of surface casing is that the string should be deep enough to reach formations that will not break down with the maximum expected mud density at the depth where the next string will be set. All later strings are suspended and sealed at the top of the surface casing by means of a casing hanger.

 Intermediate casing: The primary purpose of an intermediate casing string is to protect the borehole. A usual function of this string of casing is to protect against lost circulation in upper zones and high-pressure zones deeper in the well. In general, intermediate casing is set to seal off or protect some problem area, and provide safety for further drilling.  Liner string: Unlike casing, which is run from the surface to a given depth and overlaps the previous casing, a liner is run only from the bottom of the previous string to the bottom of the borehole. There is a minimal overlap with the previous casing, and the liner is suspended in this overlap by means of a liner-hanger. They are often cemented in place, but some production liners are suspended from the previous string. Any type of casing can be used as a liner.  Production casing (Tubing): This serves to isolate the hydrocarbons during production from undesirable fluids in the producing formation and from other zones penetrated by the wellbore. It is the protective housing for the pumps and other production equipment.


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Basic Mud Logging Running casing: Prior to running casing, the hole will be cleaned (removing the cuttings and filter cake) by doing one or more “short trips”. Once cleaned, a contract company will run wireline logs. During wireline logging, the drill crew will prepare the rig for the casing run. Once logging is over, the drill pipe elevator is removed and a heavy-duty “slip” elevator is installed to fit the casing. A “casing slip” is also installed over the rotary table. A board is rigged up in the derrick (a “stabbing board”), so that the derrick man can stand and handle the individual joints of casing and guide the elevators into position on the pipe. A pick-up line attached to the hook, raises the individual casing joints into the derrick, then the joint is stabbed (connected to another). The casing elevator is not latched to the full string of casing until the joint is made up. Following this, the casing string is lowered through the rotary table and wedged with the casing slips, ready to receive the next length of casing. Power tongs are used to ensure proper make-up of each threaded joint. There is an arrangement for intermittently filling the casing with mud as the string is run into the borehole. This prevents collapse due to insufficient hydrostatic pressure inside the casing.

Casing accessories:  Guide shoes: As the name suggests, a guide shoe is attached to the first joint of casing to be lowered into the hole. It is aluminum with a hole in the center and rounded, to guide the casing into the borehole, around obstructions.  Float collars: These devices permit the casing to literally float into the borehole, by virtue of being partially empty. It is a back pressure valve, which is closed by the outside fluid column, thereby preventing entry of the fluid as the casing is lowered into the hole. It also serves as a check-valve in the casing string, to prevent back flow of cement after being pumped outside the string. This is important because the density of the cement slurry is always greater than drilling mud. This back pressure valve serves to prevent a blowout through the casing, if a kick should occur during casing operations. A float collar also serves as a “stop” for the two plugs when cement is displaced. This action allows a quantity of slurry to stay inside the casing at the casing shoe, so that the operator has reasonable assurance of there being adequate cement outside the casing at that point.


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Basic Mud Logging  Centralizers and wall scratchers: These are attached to the casing for two main reasons: 1. To ensure a reasonably uniform distribution of cement around the pipe. 2. To obtain a competent seal all the way around the casing and with the adjoining formation. Centralizers hold the casing away from the borehole wall and therefore serve to prevent differential sticking. Wall scratchers are mechanical wall cleaning devices, attached to the casing, that abrade the hole when worked by reciprocating or rotating. This helps to provide a more suitable surface for the cement to bond to. Centralizer

Scratcher

 Wiper plugs: Wiper plugs are made of molded rubber and cast aluminum or plastic. They are designed for the following reasons: • Wipe the casing free of mud. • Separate mud from cement inside the casing. The top, or follow, plug follows cement slurry, or other fluids, down the CT string and serves as a wiper and means to separate the cement and the displacement fluid pumped behind the slurry. The top plug will seat on the top of the bottom plug when completely displaced. The bottom, or lead, plug is a device to lead the cement slurry, or other fluids, down the CT string. It also separates the fluid inside the coiled tubing and the cement slurry. Upon seating, the pins in the plug will shear at the selected pressure and allow the cement slurry to pass through the plug. The lead plug provides the seal area for the follow plug.  Cementing head: This provides the union for connecting the cementing lines from the cementing pump to the casing. This type of head makes it possible to circulate the mud in a normal manner, release the bottom plug, mix and pump the cement and pump it down, release the top plug, and displaces the cement without making or breaking any connections. Cementing heads are available in sizes from “4 1/2” to “20”, for working pressure of 2,000 to 10,000 psi. Cementing head sizes & working pressures are inversely related. Generally for smaller sizes mare working pressure and far larger sizes less working pressure are the requirements. Cementing heads could be of single plug or double plug types. Caps are “Acme” threaded or quick lack type and fitted with swivel chain assembly. PetroServices GmbH Training Center

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Basic Mud Logging 5. Cementing: Oil well cementing is the process of mixing and displacing cement slurry down the casing and up the annular space behind the casing where it is allowed to set, thus bonding the pipe to the formation. Cementing procedures are classified as primary or secondary. Primary cementing is performed immediately after the casing is run into the borehole. Its objective is to obtain an effective zonal separation and help protect the casing. Cementing also helps in the following ways: • Bonds the casing to the formation. • Protects the producing formations. • Helps in the control of blowouts from high-pressure zones. • Seals off troublesome zones (i.e. lost circulation zones). • Provides support for the casing. • Forms a seal in the event of a kick during drilling. Primary cementing: Most primary cement jobs are performed by pumping the slurry down the casing and up the annulus. There are modified techniques for special situations, such as: • Single-Stage cementing through casing (normal displacement). • Multi-Stage cementing (for wells having critical fracture gradients or requiring good cement jobs on long strings). • Inner string cementing through drill pipe (for large diameter pipe). • Outside or annulus cementing through tubing (surface pipe or large casing). • Multiple string cement (for small diameter pipe). • Reverse circulation (critical formations). Single-stage: (normal displacement technique) the general practice, once casing is set and circulation has been assured, is to pump a 10 to 15 barrel “spacer” ahead of the bottom (red) plug, which is immediately followed by the cement. The spacer serves as a flushing agent and provides a spacer between the mud and cement. It also assists in the removal of wall cake and flushes the mud ahead of the cement, thereby lessening contamination. Cement plugs consist of an aluminum body encased in molded rubber. Two plugs are usually contained in the cementing head to facilitate the operations. When the bottom plug reaches the float collar, the diaphragm in the plug ruptures to permit the cement to proceed down the casing and up the annulus. The top (black) plug, which is solidly constructed, is released when all the cement has been pumped. It is dropped on top of the cement, followed by drilling mud, to displace the cement from the casing. This plug causes a complete shut-off when it reaches the float collar. Pumping is stopped as soon as there is a positive indication (pressure increase) that the top plug has reached the float collar. To ensure good cement circulation and drilling mud displacement, movement of the casing, either by reciprocation or rotation, may be continued throughout the pumping and displacement operations. Multi-stage: Devices are used for cementing two or more separate sections behind the casing string, usually for a long column that might cause formation breakdown if the cement were displaced from the bottom of the string. The essential tool consists of a ported coupling placed at the proper point in the string. Cementation of the lower section of casing is done first, in the usual manner, using plugs that will pass through the stage collar without opening the ports. The multi-stage tool is then opened hydraulically by special plugs, and fluid circulated through the tool to the surface. Placement of cement for the upper section occurs through the ports, which are subsequently closed by the final plug pumped behind the cement.


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Basic Mud Logging

Single stage cementing

Multi stage cementing


Cementing operation

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Basic Mud Logging Secondary cementing: Secondary cement work is done after primary cementing, and includes: • Plugging to another producing zone. • Plugging a dry hole. • Formation “squeeze” cementing. The most important use of squeeze cementing is to segregate hydrocarbon producing zones from those formations producing other fluids. Squeeze cementing is also used to: • Supplement or repair a faulty primary cement job. • Repair defective casing or improperly placed perforations. • Minimize the danger of lost circulation zones. • Abandon permanently a non-producing or depleted zone. • Isolate a zone prior to perforating or fracturing. Injection of the slurry is done under pressure through perforations. The pumping rate is slow enough to allow for dehydration and initial setting, or both. Pumping is continued until the desired “squeeze” pressure is reached. Cement preparation: Bulk cement storage and handling equipment is moved out to the rig. Making it possible to mix large quantities of cement on site. The cementing crew mixes the dry cement with water, using a device called a job mixing Hopper. The dry cement is gradually added to the hopper and a jet of water thoroughly mixes with the cement to make slurry (very thin, watery cement). Weighted slurries are often used to insure a control of the formation pressure.

6. Leak off test: If drilling must continue after a casing is set, it must be determined how much is the maximum pressure that can fracture the formation at the casing shoe since it is the shallowest, unprotected formation than the lowest fracture pressure. By this measurement, drilling can continue until the mud weight (equivalent mud weight and fracture pressure equivalent mud weight) can be calculated. As the depth of drilling increases, mud weight must be increased. The maximum mud weight that can be used but not fracture the formation at the shoe is measured as follows: 1. After cement in the casing is drilled out, casing shoe is drilled out. 2. About 10 feet of new formation below the casing shoe is drilled. 3. Hole will be circulated until all of the cuttings from the new formation is out of the hole and the hole and inside casing is very clean and free from shale, sand, and cuttings. 4. Special wellhead plugs, packers at the rig floor are set. 5. A special mud with known and pre-determined weight is pumped down the hole through the drill pipe. 6. The amount of pressure that is applied is monitored very carefully and accurately. 7. Pressure is increased slowly and steadily until the formation at the shoe or below the shoe is fractured or propped open and fluid can flow into the formation. 8. At the moment of formation fracture, the pressure is measured accurately. 9. Leak-off test pressure is calculated using this pressure. Fracture pressure or fracture pressure equivalent mud weight is the combination of pressure equivalent mud weight applied and the mud weight equivalent of the hydrostatic head.


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Basic Mud Logging 7. Fishing: When great stress is placed on downhole equipment, the probability exists that sooner or later, there will be a mechanical failure and some part of the equipment will be left in the borehole. Another common source of trouble is the drill string and associated equipment becoming “stuck” in the borehole. The technique of removing pieces/section of equipment is called “fishing”. A “fish” is a piece of equipment, a tool, a part of the drill string that is lost or stuck in the hole. Small pieces, such as a bit cone, or any other relatively small non-drillable items, are called junk or “fish” in the hole. These must be removed or fished out so that drilling operations can continue.

Fishing tools: Many of the tools used to recover equipment are specially designed for the particular job. However, due to the similarity of equipment used in most drilling operations, certain standard fishing tools have been developed. A broad classification of fishing tools is: • Tools used to recover miscellaneous equipment (junk) • Tools used to recover pipe (fish)  Fishing for junk: When a relatively small piece of equipment is lost in the borehole, it may be retrieved using one of the following tools:

• “Junk” or “boot” sub: This is run immediately above the bit to catch small junk thrown up by turbulence. It is normally run before running a diamond bit so that no fragments can damage the bit. • “Finger-type” or “Poor boy” junk basket: This cuts a small core, after which weight is applied to bend the beveled fingers inward to trap the junk inside. This can be made “onthe-spot” from casing. • Core-type junk basket: This is essentially a mill shoe basket, which cuts a small core to trap the junk, and has catchers (fingers) which grip the junk on the trip out. • Fishing magnet: This is used for picking up steel fragments. • Jet bottom hole cutter: This is used when the junk is so large or oddly shaped that it cannot be readily retrieved with regular junk baskets. It breaks the junk up into smaller pieces by use of an explosive charge. • Grapple or rope spear: This is used to retrieve wireline cable in the hole.

The next figure illustrates the different tools used in fishing for junk operations.


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Basic Mud Logging  Fishing for pipe: When the drill string has actually parted or is stuck in the borehole, the operation for correcting the situation is called “fishing”. If the fish cannot be recovered, then it is cemented off and the borehole is sidetracked around it. Some of the tools used for fishing are described below. • Mill: Milling is sometimes necessary in order to dress the top of a fish so that the selected fishing tool is able to make a firm positive catch. Mills usually are bladed or blunt, tungsten carbide coated, and are attached to the end of the drill string to be lowered into the borehole. • Overshot: This is probably the first tool to be used when it is established that the top of the fish is relatively smooth. It will slide over the fish, center it, then use a rotary tap or slips to engage the fish. • Wall-hook guide: This is used if the top of the fish is located in a washed out section. It takes the place of the regular guide on the bottom of an overshot. It will engage the fish and guide it into the overshot. • Jar: This is used when the drill string is stuck or when a fish is caught in an overshot and cannot be pulled from the borehole. In normal drilling, the jar is placed in the heavy weight pipe section, while in fishing it is located directly above the fishing tool. Jarring provides a method of giving an upward jerk to free the pipe. It works similar to a trip-hammer. • Free-point indicator and string shot: When jarring has not been successful, this is used to determine at what point in the borehole the fish is stuck. It is an electronic instrument that can sense torque or pipe movement. It is lowered on a wireline as far as possible and raised slowly while the drill string is stressed. Below the stuck point, no torque will be sensed. When the instrument gives a positive indication, the “free point” is reached. The free point indicator is raised until string shot is positioned opposite the nearest tool joint (or one or two tool joints above the stuck point). Left-hand torque is applied to the drill string by the rotary table, and the primacord string shot is exploded. Loss of torque in the drill pipe is a definite indication that the tool joint has been loosened. The “back off” is completed by further left-hand rotation and by picking the pipe up a few feet. • Washover: This is a large diameter pipe with a rotary cutting shoe on the bottom. It is used to “drill over” stuck pipe to free it before fishing. • Spotting: This is used when jarring alone will not free the fish. Oil or special chemicals are spotted around the fish in an attempt to penetrate the wall cake, causing it to deteriorate and make the pipe slick. Spotting with water/oil when differentially stuck, and acid spotting when stuck in limestone are often used in an attempt to free the pipe. • Safety joint: This is a coarse-threaded joint, which may be easily released. It is run above a fishing tool in case the fish cannot be freed and the fishing tool cannot be released. If spotting and jarring do not free the fish, the “free point” is used to locate the stuck point and the upper portion of the drill pipe is “backed off”. Fishing operations can then be carried out. The next figure illustrates the different tools used in fishing for pipe operations.


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Basic Mud Logging 8. Wireline logging: Downhole logs represent continuous measurements of the drilled formations as a function of depth. The advantage of downhole logging is the ability to record, concurrently, petrophysical as well as structural information of several properties. Operating on an intermediate scale between core measurements and borehole geophysics, downhole logs are characterized by fast data acquisition over large depth ranges under in situ conditions. Most of the wells are logged by wireline systems. There usually two kinds of wireline logs: open hole logs and cased hole logs. An electric logging company is called to the well while the crew trips out all the drill string. Using a laboratory, truck-mounted for land rigs and permanently mounted on offshore rigs the loggers lower devices called logging tools (or sonde's) into the well on wireline. The tools are lowered all the way to bottom and then reeled slowly back upwards. As the tools are coming up the hole, they are able to measure the properties of the formations they pass.  Open hole logs Open hole logging is done immediately after BHA is removed from the hole. There may be one, two, or more runs of the wire line logging. In normal and most common operations, a resistivity tool, gamma, and one or more porosity tools are used (such as neutron, density, or sonic tools). In exploratory wells, more sophisticated wire line tools are used.  Cased hole logs Cased hole logging are run after casing is set and tools are used can work in the casing their signals can penetrate through the casing and into the formation. Examples of cased hole logs are cement bond logs, gamma logs for correlation, casing integrity test logs, etc.

Wireline log


Wireline tools

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Basic Mud Logging 9. Well completion: The drilling of a well is only the first stage in the total life of that well. Following the drilling, the well must be “completed” in order to produce hydrocarbons at a commercial rate. When we take a close look at the drilling processes, we can understand why completions are so important. As discussed before, when a well is drilled, the formation is first crushed by the drill bit, and then invaded by the drilling fluid. After drilling, the formation is surrounded by steel casing and weighted cement is pumped into the casing/formation annulus to bond the casing to the formation. After all of this, the target formation will need a little help if it is expected to produce hydrocarbons. A typical completion consists of three components:  A wellhead assembly – the specialized surface equipment that seals and controls the wellbore.  A casing and tubing arrangement – provides improved control over the wellbore from the surface to the producing zone.  The bottom-hole or producing zone completion – improves control over the producing zone.

 Wellhead: A production wellhead is the assembly of specialized equipment that is located at the surface of a drilled wellbore, which seals the casing and tubing previously run into the well, permitting a controlled flow of produced fluids. This assembly of valves is commonly referred to as a “Christmas Tree”. The wellhead is installed during drilling operations and then modified as required if the well is to be produced. The wellhead consists of three basic components: 1. The casing head: The casing head is a steel fitting (called a wellhead casing flange) that is connected to the top of the surface casing string at the wellhead. It supports the casing string until cemented into place. 2. The tubing head: The tubing head is similar to the casing head but is smaller, and sits atop the casing head where it supports the tubing string. 3. The “christmas tree”: The christmas tree is an assembly of fittings, valves, and chokes which control the rate of oil and gas flow from the well. It usually contains a pumping tee and gauge(s) and may contain a BOP preventer. As indicated, a well completion will vary depending on the well and reservoir characteristics, as well as its economic potential. A variety of completion methods and procedures has been developed. Basically, completions can be divided into two categories: Single zone or multiple zones. However, regardless of the type, the production casing or “oil string” must be set, the tubing arrangement determined, the packers must be properly placed and a decision must be made about the type of bottom-hole completion that will be used on the well.


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Christmas tree


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Basic Mud Logging  Packer placement: A packer is a device that seals or closes off the annulus between the tubing string and the casing string. This confines production to the tubing string. There are two basic packer arrangements: a single packer and a double or straddle-packer arrangement.

Single packer arrangement In single zone producing wells, a single packer is placed above the producing zone in order to seal off the producing zone from the casing annulus above. This type arrangement isolates the producing zone and increases production efficiency.

Straddle packer arrangement In multi-zone completions, a straddle-packer arrangement is used in each producing zone above the one at the bottom of the well. The two packers located above and below the producing zones isolate the zone and allow production from additional zones within the wellbore. A straddle-packer arrangement may also be used in a single zone completion if the producing zone is to be raised to a higher level within the formation.

 Bottom hole completions: The bottom of the wellbore may be completed in a number of different ways, depending on the producing formation. There are three basic bottom-hole completions methods: 1. Open hole completion: An open hole completion is one in which casing is set just above the target formation, leaving the bottom of the wellbore open. This type of completion is limited in use. Today, it is generally restricted to limestone reservoirs. Its major advantage is that the well completion costs are minimal, allowing recovery from marginal reservoirs. 2. Open hole with liner completion: An open hole with liner completion is one in which a liner or screen-like cylinder is placed at the bottom of the wellbore. This type of completion is usually used in loose or unconsolidated formations where sloughing may occur in the bottom of the wellbore. The liner is used in a number of variations such as gravel-packed or cemented liner completion. 3. Perforated completion: The most common method is the perforated casing completion and least used method is the open hole completion. The perforated casing completion is one in which the producing zone is sealed off by the use of a “packer” that is placed around the tubing just above the producing zone in a single zone completion, and just above and below the producing zone in a multizone completion. This type of completion is the most common in use as it is economical, versatile and can be relatively easily worked over when needed. PetroServices GmbH Training Center

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Basic Mud Logging 10. Perforating production casing: Since the pay zone is sealed off by the production string and cement, perforation must be made in order for the oil or gas to flow into the wellbore. Perforations are simply holes that are made through the casing, cement, and extend some distance into the formation. The best common method of perforation incorporates shaped charge explosives (similar to those used in armor-piercing shells). Shaped charges accomplish penetration by creating a jet of high pressure, high velocity gas. The charges are arranged in a tool called a gun that is lowered into the well opposite the producing zone. Usually the gun is lowered in on wireline. When the gun is in position, the charges are fired by electronic means from the surface. After the perforations are made, the tool is retrieved. Perforating is usually performed by a service company that specializes in this technique. Casing perforation

11. Drill stem test (DST): A drill stem test is made by lowering a valve, a packer, and a length of perforated tailpipe on the end of the drill pipe to the level of the formation. The packer set against the wall of the borehole so that it seals off the test interval from the mud column above. The valve is then opened. This procedure effectively reduces the pressure opposite the formation to atmospheric pressure, and the formation fluids can flow into the hole and be produced through the drill pipe. It amounts to a temporary completion of the well, and the produced fluids are therefore representative of the fluid production that may be expected if the well is eventually completed. A recorder in the tool makes a graph of the formation pressures. Then the packer is released and the tool retrieved back to the surface. By looking at a record of the downhole pressures and surface flows, a good measure of the characteristics and contents of the reservoir can be obtained. The full opening design allows unrestricted fluid flow and tool movement through the tubing bore. A pressure balanced bypass valve that is held open when running and retrieving prevents swabbing effect. The valve also allows debris to be washed from the top of the packer when releasing. The bypass valve is held closed by pressure from below and in turn, helps prevent upward movement of tubing. Flexibility in the DST string design gives you reservoir information from multiple zones on the same test, saving rig time and allowing you to update your reservoir model sooner. DST assembly


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Basic Mud Logging 12. Well stimulation: Well stimulation treatments were originally developed to rejuvenate old oil and gas wells by improving the porosity and permeability of the producing formations. As techniques have improved, however, they have been used more and more to initiate acceptable producing rates from new wells. The first stimulation method, nitro-shooting, started about a hundred years ago to liven up wells that had almost ceased to produce. Sometimes the improvement after shooting was spectacular. Other techniques (acidizing for carbonate formations and hydraulic fracturing for sandstones) have almost completely taken the place of shooting, although it is still employed on a limited scale.

 Acidization: In the early 1930s, acid stimulation for limestone and dolomite formations became commercially available within the oil service industry. The first treatments were with hydrochloric acid; though by 1940 mud acid (hydrofluoric and hydrochloric acids) mixtures were being used. Acidizing jobs are usually broken down into three categories: • HCl pumped into carbonates to create new openings or channels (worm holes). • HCl pumped into carbonates with borehole damage to create openings which by-pass the damaged portion. • Mud acid pumped into non-carbonates to dissolve and remove damaged portions or soluble clays. One of the most common methods of pumping acid into the well has been by bullheading. The major drawback of this method is that all the solids and fluids that have flowed into the well/tubing are forced back into the formation, which can cause more damage. A more effective method of pumping acid and introducing acid into formations is using coiled tubing (CT). Acid treatments can be used to clean the wellbore (acid washes), where the acid is pumped to the formation/perforations, then the pumping is stopped allowing the acid to enter the formation under hydrostatic pressure. These are usually short duration and when the well returns to production, the acid and by-products are removed at the surface. Another acid treatment is known as matrix acidizing, where the acid is used to dissolve away the formation to create new openings. The acid is pumped under pressure (below fracture pressure) into the formation, allowing the acid to dissolve near wellbore damage and create “worm holes” anywhere from several inches to several feet into the formation.


Acid injection into formation

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Basic Mud Logging Acid systems The most common acid systems in use are: • Hydrochloric acid: This is the most widely used acid in treatments, with concentrations ranging between 7.5% and 28%, the most common is 15%. It will dissolve calcium carbonate (CaCO3), dolomite (CaMgCO3), siderite (FeCO3), and iron oxide (Fe2O3). • Mud acid: This is a mixture of HCl and HF (hydrofluoric acid) and is generally 12% HCl and 3% HF. It will dissolve clay materials in the formation, along with feldspars and quartz. The HF will react with Na, K, Ca and Si in the clays to form insoluble precipitates, so it is advisable to always preflush with HCl. • Organic acids: These are acetic and formic acids. They are slower acting than HCl, and are generally used in high temperature wells and wells with high alloy tubing to reduce corrosion rates. • EDTA: This is ethylene diamine tetra-acetic acid. It dissolves carbonates and sulphates by chelating them. It is more expensive than the other acids and the reaction is slower.

Acid damage Acidization can be very useful in increasing the productive life of a well, if done correctly. This means proper planning with site-designed operations. If operations are carried out incorrectly, several damaging effects include: • Corrosion: Acids will dissolve tubing and casing. This is generally minimized by adding corrosion inhibitors. However, since these inhibitors are not soluble in acids, they can potentially damage the formation. • Iron precipitates: Iron from the tubing/casing will dissolve when the acid is pumped. Once the pH of the spent acid rises, the iron will precipitate out in the formation. The best practice to reduce this problem is to “pickle” the tubing (pump HCl down the tubing, then reverse circulate the acid out). • Fluid incompatibilities: If the formation contains oil or an oil-based mud was used, the acid and oil can form an emulsion (which is accelerated by the dissolved iron). Surfactants can be used with the acid, but they also can react with formation fluids. • Fines mobilization: Acids will affect the clays in the formation. Mud acids will react with clays leaching out the aluminum ions, causing silica to fall out. In addition, the pH shock of acidizing can disperse clays throughout the formation, causing them to block pore throats. • Cement bond destruction: HCL and HF will dissolve cement and break it down, especially if channels in the cement exist.

 Hydraulic fracturing In 1949, hydraulic fracturing was developed as a commercial oil field stimulation process. The procedure is to pump a viscous fluid down the well at rates and pressures to break down (fracture) the formation. The pressure is slowly increased while pumping a mixture of polymer gel and sand into the induced fractures to hold open the fissures after the hydraulic pressure had been released. The fractures created in this way are generally planar, with openings between 0.25 to 0.5 inch (though the length may several hundred feet). As with any fracturing, the openings will propagate along the lines of least resistance, so the subsurface stresses (overburden, folding, faulting, and inclined bedding) will determine whether the fracture is vertical, inclined or horizontal. Hydraulic fracturing can be used in any competent formation (sandstones, limestones, dolomites, etc.) and should be avoided in soft and plastic formations.


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MUD LOGGING PRINCIPLES AND DEFINITIONS Surface data logging in principle does not supersede human intuition, does not interfere with the drilling processes, and the results of surface data logging are available immediately. The use of this exploratory tool is widespread throughout the world. Very briefly, this tool consists of mud and cutting analysis and engineering techniques and is the technique of continuous collecting and analyzing data. Analysis reveals physical characteristics of the subsurface strata immediately as it becomes available at the surface and based on interpretation of this information, exercise of control of certain phases of the drilling operation is obtained. In addition, when plotted in graph form, this data produces a graphical representation of the physical properties of the penetrated strata. The surface data logging unit (mud logging unit) is the surface data logging engineer’s laboratory in which he continuously analyzes information relative to the strata being drilled. The instruments and equipment of the surface data logging Unit are the tools with which he compiles this information on which to base his evaluation of the characteristics of the penetrated strata and recommendations pertaining to this information. Mud logging is a service that qualitatively and quantitatively obtains data from, and makes observations of, drilled rocks, drilling fluids and drilling parameters in order to formulate and display concepts of the optional, in situ characteristics of formations rocks with the primary goal of delineating hydrocarbon “shows” worthy of testing.

PetroServives mud logging unit interior PetroServices GmbH Training Center

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Basic Mud Logging PetroServices mud logging unit interior is designed with close attention to detail and several advanced features to ensure an optimal working environment. Standing inside the unit gives the impression that the unit is much larger than its true physical dimensions. Counter and storage space is plentiful and supplies are always easily accessible. The sample preparation area is large enough to perform all sample related procedures from washing and drying the sample to autocalcimetry analysis. Geochemical cans, trays, glassware and other sample related items are stored in this area. The geologist work area is to the right of the sample preparation area and includes a computer station for up to minute data monitoring with the possibility of time or depth data playback for any period or any depth interval.

Importance of mud logging service: The mud unit is located very close to the rig floor. A number of cables extend from the logging unit to a number of sensors installed at different locations on the drilling rig. These sensors are used to measure important variables or parameters used to determine different rig operations. Mud logging service is very important for oil and gas drilling operation for the following reasons:  Collection of the rock cuttings, which is geologically described, examined for any oil shows and then packed according to the exploration company requirements.  Hydrocarbon gas monitoring while drilling. These gases are detected as a total value then are analyzed to their components.  Detection of the Hydrogen sulfide (H2S) gas while drilling which is very dangerous if it is not detected in the very early stage.  Monitoring of the drill fluid volume second by second and to immediately inform the personnel in charge about any change in that volume (Loss/Gain).  Generation of mud logs and graphs during the drilling of the well, acquisition of the data and producing a final well report.  Monitoring of the drilling parameters such as weight on bit, rotary speed, and rotary torque ...etc. In addition, to inform the personnel in charge about any anomalies or figures that could be out of the set ranges.  Monitoring the trips and updating a trip sheet at a five stand basis. This trip monitoring sheet includes the calculated/observed hole fill up or string displacement along with remarks on string overpull, tight spots and running speed.  Detection and evaluation of the formation pressure, the hydraulics optimization and the well control.  Monitoring the drilling fluid properties and report about any critical changes in these properties that might take place at any time.  Report on time any up normal drilling conditions and give advice to drilling team whenever needed.  Core catching and detailed core samples description and preparation of core log preparation. The fully computerized mud logging units provides real time applications that are able to deduce the situation on the rig and identify the current operations automatically. This allows a specific combination of parameters to be tracked and displayed on real time screens as the situation warrants. Features such as this reduce the engineers’ manual tasks and allow them to focus more on analysis and interpretation. Real time alarms are set on data at safe, mid and high levels to provide instant warning on the drill floor, where drilling parameters can be adjusted to mitigate the damaging vibrations that can induce poor penetration rate, shorter bit life, damage to the drill sting and the top drive system that might lead to drilling problems.


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MUD LOGGING CREW DUTIES AND RESPONSIBILITIES PetroServices experienced crews are specialists in operated mud logging services. PetroServices has developed its experienced workforce primarily through internal training and promotion. PetroServices typically hires junior personnel as sample catchers and trains them in accordance with our document training program. Sample catchers are promoted to mud loggers, data engineers and pressure engineers as they meet specific training and experience criteria required for advancement. PetroServices requirements for advancement include internal and external training classes with centrally controlled examinations. In addition, the candidate must have minimum number of wells logged with excellent safety records and job performance.

 Pressure engineer: Predicts and interprets pore pressure, which is used for drilling safely and casing seat selection. Usually has at least two years experience as a data engineer. The individual also must have completed the abnormal formation pressure training class and has shown competence in formation pressure evaluation. The pore pressure engineer will be required to determine and advise the drilling and exploration teams on a real time basis of estimated formation pore pressures and recommended mud weights for the safe drilling of exploration /appraisal wells using acceptable industry tool. The duties and responsibilities of the pressure engineer are as follow: 1. Overpressure zones prediction reference to recorded drilling and mud data based on calculated drilling exponent or sigma log. 2. Preparation of daily pore pressure evaluation report that contains well hydraulic calculations and mud properties recommendations. 3. Check for proper operation of the well, detection of abnormal situations and optimization of the proper rheology for drilling. 4. Lithologic analysis of cuttings, samples and core chips under microscope including visual determination of approximate porosity. 5. Producing deviation and survey record on a print table of the true vertical depth, bottom hole position in relation to the well head, the calculations of N-S and E-W displacement and doglegs. 6. Depth horizontal distance plot of the horizontal map or vertical cross section in a given azimuth. 7. Preparation of pressure evaluation log that contains drilling rate, d-exponent, Lithology, depth, mud weight, pore pressure, shale density, gas in air, bit data and drilling data. 8. Preparation and update temperature data log utilizing mud temperature parameters. 9. Produce a weekly report detailing the drilling operation and any condition of interest relating to abnormal formation pressure evaluation. 10. Preparation of different types of logs and statistical cross plots (pressure evaluation log, temperature log, .etc). 11. Preparation of final well report including all drilling events and formation pressure calculations. 12. A basic working knowledge of conversational English and be fluent in the native tongue of the country in which the work is performed. 13. The pressure engineer will, at all times, maintain a professional and responsible attitude and appearance in relations with the customer and rig personnel. PetroServices GmbH Training Center

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Basic Mud Logging  Data engineer: Analyzes drilling and logging data to make recommendations on drilling parameters. Also documents probable hydrocarbon rich pay zones. Usually has at least two years experience as a mud logger. This position requires a completed advanced mud logging, hydrocarbon evaluation, hole hydraulics and well controls training classes. The person must have proven competence in the analysis of drilling operations. The duties and responsibilities of the data engineer are as follow: 1. Monitoring and analyzing all drilling and mud data measured by mud logging equipments. 2. The data engineer is responsible for, and ensures that all equipment and sensors are maintained, serviced and calibrated according to standard company operating procedures. 3. The data engineer is responsible for, and will ensure that the unit diary, spare parts inventory, equipment status reports, calibration reports and other specified equipment monitoring reports are kept up to date. 4. The data engineer is familiar with the function, operation and routine maintenance of all logging system equipment at the location. He will implement any rig up, rig down and routine maintenance and calibration programs as instructed by the operations or unit supervisor. 5. Fluoroscopic examination of cuttings and core chips with appropriate solvents for detection of hydrocarbons. 6. All hole and pipe displacements are accurately monitored on all trips in and out of the hole. Discrepancies are to be noted and the relevant people informed. 7. Geological evaluation of all data collected and correlation of data to reference material provided by clients. 8. Total hydrocarbons and chromatographic analysis of hydrocarbons evaluation and reservoir type estimation through calculations and evaluation of different gas ratios. 9. Formation evaluation of mud logging service & fully online computerized data monitoring system. 10. Preparation of different types of reports (daily geological reports, weekly reports, final well report…etc). 11. Preparation of different types of logs and statistical cross plots (mud log, gas evaluation log, .etc) 12. All customer logs and reports are drawn and written in a neat, concise and uniform manner to PetroServices logging systems and customer requirements and are delivered to the schedule and locations required by the customer. 13. Customer requirements will be actively determined, customer satisfaction will be monitored. Information on the full range of products and services will be provided. Prespud meetings, job follow up and office calls on the customer will be performed as necessary and as required. 14. The data engineer will ensure that all safety equipment in the mud logging unit is kept in good condition. 15. Perform duties and responsibilities in a correct efficient and mature manner in cooperation with other assigned logging engineers and as directed by the unit supervisor. 16. A basic working knowledge of conversational English and be fluent in the native tongue of the country in which the work is performed. 17. The data engineer will, at all times, maintain a professional and responsible attitude and appearance in relations with the customer and rig personnel. 18. Conducting full logging unit inventory on monthly basis.


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Basic Mud Logging  Mud logger: The Mud logging Engineer is the representative of PetroServices logging systems at the well site. He is responsible for the maintenance and correct operation of the equipment supplied to provide the service. He is responsible for the collation and presentation of the information monitored in accordance with company standard procedures and customer requirements to ensure a high quality service. Usually the mud logger has 6 to 12 months experience as a sample catcher, worked as a trainee and has passed the basic mud logging and basic logging instrumentation training courses. 1. Monitoring and analyzing all drilling and mud data measured by mud logging equipments. 2. Collection, washing and bagging of cuttings, samples as directed by company’s personnel. 3. Preparation of geochemical samples as directed by company’s personnel. 4. All samples will be marked and labeled as instructed by the unit supervisor and as per the customer requirements. Storage and transportation will be as directed by the unit supervisor. 5. Lithologic analysis of cuttings, samples and core chips under microscope including visual determination of approximate porosity. 6. Fluoroscopic examination of cuttings and core chips with appropriate solvents for detection of hydrocarbons. 7. Geological Evaluation of all data collected and correlation of data to reference material provided by clients. 8. Make sure that all equipment and sensors are maintained, serviced and calibrated according to the standard company operating procedures. 9. The Mud logger is familiar with the function, operation and routine maintenance of all logging systems equipment at the location. He will implement any rig-up, rig-down and routine maintenance and calibration programs as instructed by the operations or unit supervisor. 10. The Mud logger is familiar with the hardware configuration of the computer system and is capable of operating the software. 11. All hole and pipe displacements are accurately monitored on all trips- in and out- of the hole. Discrepancies are to be noted and the relevant people to be informed. 12. The mud logging will at all times maintain a professional and responsible attitude and appearance in relations with the customer and rig personnel. 13. Total hydrocarbons and Chromatographic analysis of hydrocarbons evaluation and reservoir type estimation through calculations and evaluation of different gas ratios. 14. Formation evaluation of mud logging service & fully online computerized data monitoring system. 15. Preparation of different types of reports (daily geological reports, weekly reports, final well report…etc). 16. Preparation of different types of logs and statistical cross plots (mud log, ..etc) 17. All customer logs and reports are drawn and written in a neat, concise and uniform manner to logging systems and customer requirements and are delivered to the schedule and locations required by the customer. 18. Assist in the training of the new employees in the fundamentals of logging techniques and job requirements. 19. A basic working knowledge of conversational English and be fluent in the native tongue of the country in which the work is performed. 20. The data engineer will, at all times, maintain a professional and responsible attitude and appearance in relations with the customer and rig personnel. 21. Conducting full logging unit inventory on monthly basis. PetroServices GmbH Training Center

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Basic Mud Logging  Sample catcher: Typically an entry level training position for mud loggers. Retrieves samples from the rig mud system for analysis and assists mud loggers, data engineers and pressure engineers. Sample catchers ensure the correct evaluation of data by providing the basic item for evaluation - accurately caught geologic samples. The primary objective of sample catching is to assist in the efficient completion of oil and gas wells by providing correctly lagged and reliably labeled samples. The following illustrates the general responsibilities of a sample catcher with respect to rig site duties. 1. Ensure that representative geologic samples are caught throughout the drilling or reaming phases of the well program. 2. Perform the collection of cuttings samples, from the proper lagged depths and at the proper intervals as required for evaluation. 3. Wash and screen samples, divide them into correct portions, and pack them by sets for the client, partners and trade. 4. Assist in core recovery and packaging as required. 5. Keep in mind the basic concept of service; ensure that all tasks performed for the client meet or exceed the customer's standards. 6. Assist logging crew and data engineers to perform normal routine maintenance of sensors and other equipment. 7. Assist logging crew and data engineers to perform regular and frequent calibration checks of instruments. 8. Be aware of safety regulations and procedures as specified by the client, PetroServices, and relevant safety authorities. Respect safety regulations in all circumstances. 9. Be aware of and implement all requirements of the client's systems within the scope of operations. The major objective is to provide the best services in order to meet and/or maintain client satisfaction. Ensure that the quality directives are understood and implemented. 10. A basic working knowledge of conversational English and be fluent in the native tongue of the country in which the work is performed.


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Basic Mud Logging

MUD LOGGING THEORY & LAG CALCULATIONS While drilling, mud is continuously being pumped down through the drill pipe to the bottom of the hole, out through the bit, up through the annulus (around the drill pipe) to the surface, out the flow line, over the shale shaker into the mud pit, through the mud pump, up the standpipe, through the kelly hose and swivel, down the kelly and back into the drill pipe. During the circulation, the drill bit continuously cuts off small particles of formation, called cuttings, which are carried up, out of the hole by the mud and are caught, and strained, out of the mud at the shale shaker. It is at the shale shakers that access to the drilled formation information is gained. In short, surface data logging is made practical by the use of the returning mud stream as a medium for communication with the bottom of the hole. The theory is that the drilled formation is carried to the surface partly in pieces of formation and deposited on the shale shaker in the chronological order that it was drilled, and partly in gases released into the mud. Surface data logging is a matter of extracting the information that is delivered by the returning mud for restoration of the in place characteristics of the formation upon which a model is formulated and the well control decisions derived from this. Before being broken up by the bit and carried to the surface by the mud, the formation lays in situ under formation pressure, however great or small that may be. Historically, the drilling mud exerts a pressure (on the formation being drilled) considerably greater than that which the formation exerts on the mud. Thus, there was thought to be considerable flushing (replacement of hydrocarbon liquids and gases by the drilling mud) of the formation ahead of the bit by the mud filtrate. The factors which affect the amount of oil and gas remaining in the formation after being flushed to some extent and which in turn affect the amount of oil and gas entrained in the drilling mud are: • Depth • Rate of penetration • Hole size • Volume of drilling fluid being circulated • Physical properties of the formation • Properties of the drilling mud How near to “balance” the well is drilled. Balanced drilling is a name given to the use of mud weights, which will result in the drilling mud column exerting almost the same, or a very little amount more, hydrostatic pressure on the formation fluids and gases than the formation fluids exert back on the mud column. Overbalanced drilling is the case of too much mud weight resulting in more pressure exerted by the mud column than the formation exerts back. Balancing of pressures results in greatly improved drilling rates and formation evaluation. Underbalanced mud weights can result in a potential “blowout” situation. As the cuttings travel to the surface up the annulus, they undergo a pressure reduction, resulting in a release of formation fluids from the cuttings. In addition, the “jetting” action of mud going through the bit causes a reduction in the hydrocarbon content of the cuttings. Therefore, by analyzing the cuttings, drilling mud and drilling parameters for hydrocarbon associated phenomenon, we can develop a great deal of information and understanding concerning physical properties of a well from surface to final depth.


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Basic Mud Logging Lag application: It is obvious that at the instant a drilled sample is delivered to the shale shaker that the bit has penetrated some distance deeper into the hole from the time when that sample was cut loose from the formation, so that sample at the surface will be from a depth shallower than that at which the bit is currently drilling. For example, if it takes an hour for a sample to reach the surface from the bottom of a 6,000 foot hole, and the bit is drilling at a rate of 100 feet per hour, the well depth will 6,100 feet when the samples from the depth of 6,000 feet are just reaching the surface. This critical interval of time is called “lag” and is measured in terms of the mud pump cycles or in time. This lag applies to all downhole information except penetration rates. This lag always exists and, theoretically, changes continuously as the hole deepen. Likewise, the length of the lag time is dependent on anything that changes the hole volume, such as hole washout or channeling of the mud flow in the annulus. It is necessary to always know the lag and apply it continuously to returning samples in locating accurately the depth from which they came. Because of the factors present which cause the lag to change, the lag must be checked and rechecked frequently and regularly. A lag determination should be run at least once each 24 hours or once every 500 feet, whichever occurs first. When drilling an average size hole less than 10 inches in diameter, every 500 feet may be enough. If the hole is larger than 10 inches in diameter, the lag determination should be run at least every 250 feet.

Running the lag: The lag can be determined by injecting a tracer in the mud in the drill pipe at the surface when the kelly is broken off and counting the number of strokes that the mud pumps have to make in the interval between injection and recovery at the shale shakers. From this total pump cycle the number of cycles required to pump the tracer down the pipe to the bit must be subtracted. This arithmetic result is called the “lag” for the particular tracer material that was used. There are two main types of materials that are used today for determination of the lag. These are Lost Circulation Material (LCM) and calcium carbide. This last material when placed in the drill pipe reacts with the water in the mud to form acetylene gas and is picked up by the gas detector and gas chromatograph. It is important to remember that calcium carbide only reacts with water, so it cannot be used with an oil based mud. The calcium carbide method is the most convenient for determining the lag. The lag obtained in this manner is called a “gas lag.” For logging operations, the gas lag is normally used. When a lag tracer is placed in the drill pipe, a stroke counter must be set to monitor the number of strokes required for the tracer to travel down the drill string and back up the annulus. When the lag tracer appears at the shale shaker or the carbide gas reading appears on the gas detector on its return to the surface the total number of strokes is recorded. It is then necessary to subtract the calculated number of strokes down the drill string (down pipe factor); the result is the lag. Calculate the number of barrels from the number of strokes and enter this adjustment in the computer. The lag determination in terms of pump strokes have advantages over a lag determined based on time. The reason is that when the pumps are stopped, the clocks continue to run, and a factor may be introduced which must be taken into account. Another factor is that the lag determined in terms of time is correct only for one pump speed or that particular speed at which the lag was run, whereas, the lag in pump cycles is accurate for any pump rate. PetroServices GmbH Training Center

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Basic Mud Logging Another item to be aware of at this point is the reaction of calcium carbide with drilling mud forming acetylene, which will be read on the gas detector as a gas peak. You will be able to distinguish this from a formation gas as it will show up on the gas chromatograph accompanied to hydrocarbon components.

Hints and precautions concerning the use of lag materials: 1. Put the lag material in the drill string, not in a mouse hole single. 2. Note that the amount of lag material used may have to be increased as the depth increases. 3. Observe samples during drilling breaks as check on lag calculation accuracy when the opportunity arises. 4. Observe connection gases when possible; do not use trip or short trip gases as a check. 5. Make sure the shale shaker has not been bypassed. 6. Be sure to record all pertinent data for future referral, as this can be critical in future discussions on the matter.

 Calculating down pipe volume: The down pipe factor is expressed in terms of volume (barrels of mud) or strokes (pump cycles); that is, for a known drill pipe length and inside diameter (ID), the capacity of the drill string in barrels can be calculated. Given the following data, we can determine the down pipe factor: Hole depth = 11,000 feet Drill string = 5 inches OD and 4.276 inches ID Pump data = Triplex, single action: 6-inch liner, 11-inch stroke, 95% efficiency 1. First calculate the volume of the string with one of the following formulas: ID2 × 0.00097 = barrels per foot or ID2 ÷ 1029.4 = barrels per foot (4.276)2 × 0.00097 = 0.0177 barrels per foot or (4.276)2 ÷ 1029.4 = 0.0177 barrels per foot 2.

Multiply the drill string capacity by the length of the drill string to obtain the total number of barrels. 0.0177 × 11,000 = 195.4 barrels

3. To obtain the number of strokes for the down pipe factor you will have to calculate the pump output in barrels. The formula is as follows: bbl/stk = 0.000243 × (liner ID)2 × L ID = liner size in inches L = stroke length of the pump The output of a 61/2-inch × 11-inch PZ-11 triplex is: bbl/stk = 0.000243 × (6.5)2 × 11 = .1129 bbl/stk at 100% efficiency Since the pumps are, only 95% efficient multiply by .95 0.1129 × 0 .95 = 0.1073 efficiency corrected barrels per stroke To obtain the down pipe factor in strokes, divide the volume (in barrels) by the pump output: 195.4 ÷ .1073 = 1821 strokes Note: The previous calculations did not take into account the fact that the bottom hole assembly normally has a smaller ID than the drill pipe. PetroServices GmbH Training Center

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Basic Mud Logging  Calculating bottoms up lag: To calculate the lag the hole dimensions must be known as well as the drill string dimension. Most holes have at least two sections of different diameters and towards the end of the well may will have more (riser, casing liner, and open hole). Added to this is the fact that the drill string will usually have sections of different diameters (drill pipe, heavyweight drill pipe and drill collars, etc). Two techniques may be applied to calculating the annular volume, which are: In The first method, the lengths and the dimensions of each section of the annulus are determined; the volumes are calculated and totalized. Then the lag equations are applied to determine the equivalent times and strokes. The second method involves calculating the volume of the hole and the volume of the drill string (metal and internal capacity) and then subtracting the values from each other to determine the lag time and strokes for the whole well. The first method is the one preferred because it informs the logger of the exact nature of the various annular sections and their individual volumes. An alternate to the tracer method of calculating the lag is available. This is by calculating the annular volume by using either one of the two approaches: 1. Principles of volume 2. Capacity/displacement tables Using similar data as for the previous example: Hole depth = 11,000 feet Drill pipe = 5 inches OD by 4.276 inches ID Pump data = .0997 barrels per stroke In addition, we must consider the following data: Hole size = 12.25 inches Depth of last casing = 9,500 feet Size of last casing = 13.375 inches OD by 12.347 inches ID (72 pounds per foot) Size of Drill collars = 8 inches OD by 3 inches ID (147.0 pounds per foot) Length of Drill collars =500 feet These specifications result in a pictorial representation of the well geometry as follows: As noted, there are three distinct annular sections. • Annular section 1 is formed by the drill pipe and casing • Annular section 2 is formed by the drill pipe and open hole • Annular section 3 is formed by the drill collars and open hole The simplest method of arriving at a total annular volume is to calculate each section independently and the add up the results. Capacity of the annulus in barrels per foot = (hole size or casing ID)2 - (drill pipe outside diameter)2 × 0.00097 or (hole size or casing ID)2 - (drill pipe outside diameter)2 ÷ 1029.4


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Basic Mud Logging Annular section 1 = (casing ID2 - drill pipe OD2) × 0.00097 (12.3472 - 52) × 0.00097 =.1236 barrels per foot Next barrels per foot × section length = barrels 0.1236 × 9500 = 1174 barrels Annular section 2 = (hole size2 - drill pipe OD2) × 0.00097 (12.252 - 52) × 0.00097 = .1213 barrels per foot Next barrels per foot × section length = barrels 0.1213 × 1000 = 121.3 barrels Annular section 3 = (hole size2 - drill collar OD2) × 0.00097 (12.252 - 82) × 0.00097 = .0835 barrels per foot Next barrels per foot × section length = barrels 0.0835 × 500 = 41.7 barrels Adding up the sections, we have: 1174 + 121.3 + 41.7 = 1337 barrels total annular volume To convert this volume into pump strokes, divide the total annular volume by the pump output: 1337 barrels ÷ 0.0997 barrels per stroke = 13410 strokes Divide the total strokes by the pump rate per minutes to obtain the bottoms up time. 13410 strokes ÷ 150 strokes per minute = 89.4 minutes The lag stroke is then (13410 strokes) and its equivalent lag time according to rig pump rate is (89.4 minutes).

Note: When logging, it will be observed that the calculated lag will invariably be less than that obtained by using the tracer method. Reasons for this are: • Lag tracer materials or cutting will tend to slip behind the velocity of the mud with respect to their relative densities and the particular mud's carrying capabilities. • Enlargement of the hole, due to erosion by the mud, is not accounted for when making the lag calculation. • Mud flows are sometimes turbulent which results in a tendency for the cuttings and tracer materials to rotate up the annulus rather than rising uniformly. Due to the characteristics of drilling mud in laminar flow, the center annulus flow rate tends to be faster than that near the walls; thus, cuttings in the center annulus region tend to be moved over into the slower flow areas and subsequently are again moved back into the faster region. This is a similar effect to the previous paragraph although the rotational effects are much less harsh.


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Basic Mud Logging Cumulatively, these effects tend to delay the arrival at the surface of cutting samples. Conversely, gas samples will tend to rise at the same or possibly at a slightly higher rate than the mud, particularly if the mud is relatively thin. As gas rises in the annulus, a reduction of hydrostatic pressure will be exerted on the samples resulting in an expansion of the gas in proportion to its volume and original pressure. Hole enlargement will, however, have a similar effect on gas samples as with heavier materials. The net result is that gas samples will tend to arrive at the surface sooner than cuttings. In any event, a lag calculation is a good approximation but should be corrected or checked for accuracy and corrected as necessary by noting the arrival of cuttings from a drill break or connection gas. As a well deepens, the pump liners are sometimes replaced by liners of a smaller diameter make a periodical check as to the liner size. This normally takes place when a new casing string is run. Most drilling rigs are equipped with two mud pumps, whereas, most of the deep water semisubmersible rigs will have three mud pumps. One of these pumps is normally used to boost the riser during drilling operations. Ensure that the software is properly configured to pumps, which are on the hole. When the rig pumps are stopped the mud column stops. Also, if drilling is suspended and the well circulated out, the flow of information that is collected at the shale shakers and new information is no longer being supplied at the bottom of the hole. After the expiration of the lag, the bottom of the mud column will have reached the surface. Without the lag as an indexing tool, all the mud and cuttings analysis would apply to formation only at unknown depths and, as common sense would indicate, this information is almost useless without knowing at what depth the analysis pertains to. Therefore, with the lag calculation it is known exactly to what depths these analysis apply. In conclusion, the annulus represents a continuous column of surface data logging information moving up and out of the hole, which is transferred to the computer by the logging engineer as part of the daily routine.

Points to note are: • Drill pipe, drill collars and casing sizes are often referred to by weight of the item under consideration. It is therefore necessary to refer to charts and tables for actual dimensions: 87.9 lb/ft drill collars = 6-inch OD × 1.75-inch ID 19.5 lb/ft drill pipe = 5-inch OD × 4.276-inch ID 36.0 lb/ft casing = 9.625-inch OD × 8.921-inch ID • Unless the hole is totally cased the actual lag will always be greater than the calculated. Therefore, use sample data or run a tracer lag to accurately set the lag value.


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Basic Mud Logging

SAMPLES COLLECTION AND DESCRIPTION An accurate sample description is the basic function of geologic work – the foundation on which the entire structure of subsurface analysis rests. This manual has been assembled in an effort to furnish a convenient reference on standard stratigraphic procedures. Techniques of collecting, preparing, examining, and describing well cuttings and core samples are set forth. A description can become so detailed as to obscure important characteristics of the samples; the surface data logger should learn to be selective and report only the important details. Sample analysis should be made carefully and attentively. The accuracy of a study is dependent upon the quality of the samples and the proficiency of the surface data logger. Careful initial examination and description of the samples will save time and prevent the necessity for re-examination. There will be times when it is impossible due to well conditions for the surface data logger to accomplish this the first time. It is more important that the samples be caught first. Experience and good training are essential for making a good interpretive log. Generally, the surface data logger examining the samples is best qualified to recognize lithologic and formational contacts. Although formation contacts should be picked based on sample data rather than on mechanical logs, the latter, as well as the drill rate, can also be useful in defining boundaries of specific lithologic units, and zones of interest.

1. Collecting cuttings samples: First and most important step in evaluating any formation drilled is the collection of the drilled cuttings. If this step is not done properly, then, even if all the following steps are perfect, the information obtained is worthless to the geologist and petrophysical engineer. Drilled cuttings are physical, tangible pieces of rock. It took the forces of nature millions of years to lay them down, and it cost the oil companies much time and millions of dollars to recover them. Aside from their immediate value, the cuttings can be saved and re-evaluated in the future using techniques and knowledge that have yet to be discovered. However, if the cuttings simply fall overboard, then their information is gone. The knowledge they carry is also lost when they become mixed with other cuttings and we no longer know the depth of origin. Good cuttings and mud sample collection requires an accurate lag (indication of origin of depth), a means of collecting representative samples, and efficient use of available time.

 Shale shaker samples: Almost every rig has a shaker screen for separating the cuttings from the mud when they reach the surface. Most shaker screens are of the vibrating type, but the cylindrical rotating type may be used in hard rock areas. When a shaker screen is used, the mesh size should be small enough to separate small cuttings from the mud. There must be a board or box placed at the foot of the shaker screen with the most cuttings coming over to collect the cuttings. The samples taken here will result in a composite sample that is representative of the complete sample interval (i.e., 10 feet, 30 feet).


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Basic Mud Logging Cuttings caught directly from the shaker screens only represent a spot check of a couple of inches, and therefore, miss most of the cuttings from the sample interval. The board or box should be cleaned after each sample is caught so there will not be mixing of the cuttings from different depth intervals. It is important that if all the lagged intervals have been circulated from the hole, that the board or box be cleaned just before any new formation is due at the surface.

 Settling box samples: Although the shaker screen cuttings sample retrieval method is the one most often used, another means of collecting samples is the settling box. A settling box should be rigged up in such a way that part of the mud from the flow line is diverted into the box (through a two inch line for example). The mud flows through the settling box, over a removable slide gate in the opposite end of the box, and into the mud pit. The flow through the settling box reduces the velocity of the mud, which permits the cuttings to settle to the bottom of the box where they can be scooped out with a sample spoon. After collecting a sample, the slide gate is lifted and the remaining cuttings are scraped and flushed away to prepare the box to collect the sample from the next sample interval. Using a settling box ensures that a composite sample is collected for each sample interval. A settling box employs the sluice box effect, and it provides the surest means of collecting small cuttings and fine grained sand. The settling box is practically the only means of catching samples in lost circulation zones when the shakers are being bypassed. Setting up a settling box before hand assures that no samples will be missed in the event circulation is lost, and that there will be uniform sample catching throughout the hole. Samples should be caught at intervals that are more frequent in a potentially productive zone. In addition, once a zone is found to contain a hydrocarbon show, samples should be caught even more frequently. The relative data analysis can be determined quickly since the surface data logging engineer knows what to look for.

 Hints and Precautions: 1. If a sample is missed for any reason, mark the sample bag and the data sheet that it was missed. A missed sample is better than a “faked” sample. 2. During a potentially productive zone, or a known productive zone; catch the samples as often as possible. This can be accomplished by placing the samples in suitable containers, marked with the correct lag depth, and set aside until there is time to examine them carefully. It is better to be late with information than to be on time with very little information concerning the interval.

Wet sample


Spot sample

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Basic Mud Logging  Collecting “wet” samples: A “wet” sample is an unwashed cuttings sample taken for paleontological and petrological examination in the oil company’s laboratories. It can be a tinned sample, or just a sample put straight into a fine mesh cloth bag, labeled, and left out in the sun to dry before tying it up into bundles and bagging it up into labeled sacks. Note: To avoid losing a sample takes care in pen selection. Do not use washable ink. A bag of samples with the label missing is useless. Care should be taken to adequately fill the sample sacks. The operating company usually requests that the wet samples be placed into plastic bags before they are put into cloth bags. If this is done, be sure that the top of the plastic bag and the top cloth bag are both tied in such a manner that the samples will not be pressed from the bag during shipment to the customer’s laboratory.

Wet sample bags examples It is a good procedure to collect a sample of all mud additives and their data sheets and ship them with the first set of samples that are shipped to the customer’s laboratory. Many of these mud additives can affect the rocks and the information that they contain.

3. Washing the cuttings:  Washing cuttings from water based mud: Washing and preparing the cuttings sample for examination is as important as the examination itself. The technique must be adapted to the area and the type of material being examined. In hard rock areas, the cuttings are usually easy to clean. Most of the time washing is just a matter of hosing the sample in a mud cup with a jet of water to remove the film of drilling mud from the surface of the cuttings. Washing the cuttings from areas of recent geological age (cuttings that are less compacted and consolidated) is, however, more difficult, and requires taking several precautions. The primary concern is that the clays and silts that are present are often soft and dispersible in water. Indeed, they are often of a consistency that will disperse and “make mud.” When cuttings of this type are washed, there is a tendency for the wash water to dissolve the clay and wash it away. This should be taken into account. The surface data logger should always keep in mind that the clay that is washed away is not foreign material, but it is a part of the sample. It should be logged accordingly. The sample should be washed no harder than is necessary to remove the drilling mud.


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Basic Mud Logging Cuttings from zones of lost circulation are intermixed with lost circulation material. This material can usually be floated out of the sample container by flooding it with water, leaving only the cuttings. This method, however, is sometimes very time consuming. A settling box for catching the sample is an excellent solution to this problem since it flushes most of the lost circulation material away from the cuttings. It is important for the surface data logger to recognize the difference between any lost circulation material and true formation cuttings. After the cuttings have been washed to remove the drilling mud, they should be washed through a 5-mm sieve to remove sloughed shale and then into a 20-mesh, an 80-mesh sieve, and then into the sieve receiver assembly. It is generally accepted that the drilled cuttings will pass through the 5-mm sieve and the material that does not pass through is cavings. The 5-mm catch should be monitored closely even though these fragments are generally not generated by the bit. First of all, the amount of fragments in the sieve can indicate changing downhole conditions. An increase in the volume of these fragments can mean the hole is becoming near balanced pressure wise and formation is popping into the wellbore; these pieces are generally curved or splintery. It can also indicate that a water sensitive formation has been encountered and it is swelling due to the mud filtrate and sloughing into the hole. A sudden decrease in the volume of the 5-mm sieve chips can indicate an easily dissolvable formation has been cut and the chips are being reduced to very fine particles. After the sieving, a small portion of the washed sample should be put onto one of the trays provided for microscopic inspection and then drained. A larger sample should be placed on another tray, then drained and dried before it is placed into a labeled envelope and boxed for the oil company laboratory analysis. The tray for immediate examination should contain only a single layer of cuttings. This is important when considering the relative percentages of the different materials contained in the sample.

 Washing cuttings from oil based mud: In the case of oil based mud, the cuttings are quite representative of the formation because this type of mud decreases sloughing so there is little dispersion of the shale. At the same time, however, cuttings contained in oil based mud pose a problem with washing and handling. They cannot be washed in water alone. It is necessary to use a detergent on the cuttings to clean off the drilling mud that interferes with seeing the cuttings fragments for description. Set up two containers, such as two 5-gallon buckets. One should contain a nonfluorescent solvent (preferably Varsol or naphtha). This should be used for the first washing to remove the outer coating of drilling mud from the cuttings. In the other container, mix a solution consisting of a commercially available detergent into 5 gallons of water. Wash the cuttings in the detergent solution to remove the solvent. After this, they can be washed in water as usual. To make a good inspection for lithology and staining, the cuttings must then be broken or crushed. PetroServices GmbH Training Center

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Basic Mud Logging 3. Sample description: The quality of a mud log is a direct measure of the quality of the samples that were collected and prepared. Clean, good quality samples are exceptions rather than the rule. The surface data logger describing the samples must learn to make his interpretations from samples of widely varying quality. Cavings and other contaminants must be recognized and disregarded. Several methods of examining samples are in use throughout the industry. Some surface data logger examines one sample at a time; others lay out the samples in compartmented trays so that a sequence of from five to ten samples may be examined at one time. The following procedure is recommended:    

The samples are laid out in a stack of five-cell trays with the depths marked on the trays. The cuttings should just cover the bottoms of the trays. It is desirable to separate the obvious cavings by sieving the samples. Attention should generally be focused on the smaller cuttings with angular shapes and fresh appearance.

The technique of scanning samples before logging them in detail has many advantages. In addition to helping the surface data logger pick tops and lithologic changes it may also aid him in determining the extent of porous and hydrocarbon bearing intervals. However, the principle advantage of this technique is that it provides the surface data logger the opportunity to observe and interpret depositional sequences. When sample intervals are laid out in sequence subtle changes in texture, mineralogy, color and facies often become apparent even before microscopic examination. Thus, the surface data logger is alerted to look for these changes when making the detailed sample examination. This method of examining samples encourages surface data logger to observe and log lithologic rather than sample interval units. It is still important that the surface data logger do a complete and thorough description of each sample. Textures in carbonate rocks can be clearly observed with the aid of wetting agents such as mineral oil, glycerin, clove oil, etc. A further improvement of this technique is the use of transmitted light as described below.

Use of transmitted light: Textural and structural details often become evident when light is transmitted through thin slivers of carbonate rock. This technique is particularly useful for the routine examination of drilled cuttings. Cuttings selected for their thin, platy shape are etched lightly in dilute HCl, placed in a clear pyrex spot plate, and then completely covered with a wetting agent. Light is then transmitted through the chips by the use of a substage mirror, or a small reflecting mirror placed directly on the stage and underneath the plate. A mixture of water and glycerin is recommended as the wetting agent because: (1) It evaporates slowly. (2) Chips may be washed clean with water after examination.


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Basic Mud Logging Order of written description: Written descriptions are required in a standardized order of description because of the following: (1) it reduces the chance of not recording all important properties, (2) increases the uniformity of description among surface data logger, and (3) saves time in obtaining information from descriptions. The following order is used: 1. Rock type - followed by classification 2. Color 3. Texture - including grain size, roundness, and sorting 4. Cement and/or matrix materials 5. Fossils and accessories 6. Sedimentary structures 7. Porosity and permeability 8. Hydrocarbon shows 9. Procedures for rock and mineral identification I. Rock Types The recording of rock type consists of two fundamental parts: the basic rock name (e.g., dolomite, limestone, sandstone), and the proper compositional or textural classification term (e.g., lithic, oolitic grainstone). II. Color Color of rocks may be a mass effect of the colors of the component grains, or result from the color of the cement or matrix, or staining of these. Colors may occur in combinations and patterns, e.g., mottled, banded, spotted, variegated. It is recommended that colors be described on wet samples under ten-power magnification. If is important to use the same source of light all the time and to use constant magnification for all routine logging. General terms, such as dark grey and medium brown, generally suffice. Ferruginous, carbonaceous, siliceous, and calcareous matter are the most important staining or coloring agents. From limonite or hematite come yellow, red, or brown shades. Gray to black color can result from the presence of carbonaceous or phosphatic material, iron sulfide, or manganese. Glauconite, ferrous iron, serpentine, chlorite, and apatite impart green coloring. Red or orange mottling is derived from surface weathering or subsurface oxidation by the action of circulating waters. The colors of cuttings may be alerted, after the samples are caught, by oxidation caused by storage in a damp place, insufficient drying after washing, or by overheating. Bit or pipe fragments in samples can rust and stain the samples. Drilling mud additives may also cause staining. Place a wet sample next to color swatches, to determine which color most closely matches the dominant color of the sample.


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Basic Mud Logging III. Texture Texture is a function of the size, shape, and arrangement of the constituent elements of a rock.  Grain or crystal sizes Size, grades and sorting of sediments are important characteristics. They have a bearing on the porosity and the permeability of the rocks and may be a reflection of the environment in which sediment was deposited. Size classifications are to be based on a Wentworth scale. The surface data logger should not try to record size grades without reference to a standard comparator of mounted sieved sand grains. Other comparators are photomicrographs of thin sections showing both grain size and sorting. Both simple and useful is a photographic grid of half-millimeter squares, which may be placed near the microscope.


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Basic Mud Logging Rock sample examples:

Quartz pebbles: Generally, white, clear or milky, but iron staining can give an orange hue. Often seen in Putnam and Clay counties, but may be seen elsewhere. Sand: Can be most any color. Grains generally composed of quartz or calcite. If grains are cemented together, it may be sandstone. Often found with clay, limestone, or phosphate. Sand with clay: Sand sized grains held together with clay. Sample easily crumbles or can be shaped if sufficient clay sized material. Grains are limestone, phosphate, shell pieces, and quartz in this sample.

Clay: Can be most any color green, olive, gray, bluish green, and grayish green are most common in. Clay can be squeezed into a ribbon or rolled into shapes. Often mixed with sand, shell, or phosphate. Coquina: Coquina is composed primarily of shell hash that has been tightly cemented together. Shell beds look similar in drill cuttings, but may have more clay and sand.

Salt: White, dirty white, and off white. Generally, sand with quartz and phosphate (black or brown grains in photo) or heavy minerals (titanium-based), may exist with salt.


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Basic Mud Logging Chert: Can be most any color. Rock is very hard and breaks with sharp edges or conchoidal fracture. Occurs as nodules, lenses, beds, or within fractures or voids. Often called flint.

Limestone: Component grains form a framework held together by calcite cement, which appears as clear to milky white between the grains. This sample is mostly limestone grains, but brown dolostone can also be seen. Limestone with fossils: Similar to the above in that grains comprise the majority of the rock and the inter-granular space is filled with hardened lime mud. Enlargement shows that a portion is fossil coral with mud infilling. Dolostone: It is recrystallized dolostone. In this sample, rhombohedral shaped dolomite crystals can be seen in the enlargement. Acid reaction may be barely perceptible when applied. A hammer was needed to break the sample. Dolostone: Similar to above, except grains are supporting the rock. This sample has limestone, dolostone, and chert grains with some fossil pieces. The limestone grains will fizz more vigorously than the dolostone or chert. Gypsum: Generally white but may have bluish tint or brown staining. Soft can scratch with fingernails. Occurs as nodules, beds, or infilling in voids or fractures. Flat faces of crystals may be seen. PetroServices GmbH Training Center

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Basic Mud Logging  Shape Shape of grains has long been used to decode the history of a deposit of which the grains are a part. Shape involves both sphericity and roundness. Sphericity refers to a comparison of the surface area of a sphere of the same volume as the grain, with the surface area of the grain itself. For practical purposes, distinction is usually made in large particles based on axial ratios and in grains by visual comparison with charts. Roundness that refers to the sharpness of the edges and corners of a fragment is an important characteristic that deserves careful attention in detailed logging. Five degrees of rounding are described as follows: Angular edges and corners sharp, little or no evidence of wear. Subangular faces untouched but edges and corners rounded. Subrounded edges and corners rounded to smooth curves; areas of original faces reduced. Rounded Original faces destroyed, but some comparatively flat faces may be present; all original edges and corners smoothed off to rather broad curves. Well rounded no original faces, edges, or corners remain; entire surface consists of broad curves, flat areas are absent.

Sorting Sorting is a measure of the size frequency distribution of grains in a sediment or rock. It involves shape, roundness, specific gravity, and mineral composition as well as size. A classification given by Payne (1942) that can be applied to these factors is: Good: 90% in one or two size classes Fair: 90% in three or our size classes Poor: 90% in five or more size classes Values that are more precise may be determined by direct comparison with sorting comparators.


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Basic Mud Logging IV. Cement and matrix Cement is a chemical precipitate deposited around the grains and in the pore spaces of sediment as aggregates of crystals or as growths on grains of the same composition. Matrix consists of small individual grains that fill the pore spaces between the larger grains. Cement is deposited chemically and matrix mechanically.

The order of precipitation of cement depends on the type of solution, number of ions in solution and the general geochemical environment. Several different cements, or generations of cement, may occur in a given rock, separately or overgrown on or replacing one another. Chemical cement is uncommon in sandstone which has a clay matrix. The most common cementing materials are silica and calcite. Silica cement is common in nearly all quartz sandstones. This cement generally occurs as secondary crystal overgrowths deposited in optical continuity with detrital quartz grains. Opal, chalcedony, and chert are other forms of siliceous cement. Dolomite and calcite are deposited as crystals in the pore spaces and as aggregates in the voids. Dolomite and calcite may be indigenous to the sandstone, the sands having been a mixture of quartz and dolomite or calcite grains, or the carbonate may have been precipitated as a coating around the sand grains before they were lithified. Calcite in the form of clear spar may be present as vug, or other void filling in carbonate rocks. Anhydrite and gypsum cements, are more commonly associated with dolomite and silica than with calcite. Additional cementing materials, usually of minor importance, include pyrite, generally as small crystals, siderite, hematite, limonite, zeolites, and phosphatic material. Silt acts as a matrix, hastening cementation by filling the pore spaces, thus decreasing the size of interstitial spaces. Clay is a common matrix material, which may cause loss of porosity either by compaction or by swelling when water is introduced into the formation. Argillaceous material can be evenly distributed in siliciclastic or carbonate rocks, or have laminated, lenticular detrital or nodular form. Compaction and the presence of varying amounts of secondary quartz, secondary carbonate, and interstitial clay are the main factors affecting pore space in siliciclastic rocks. While there is a general reduction of porosity with depth due to secondary cementation and compaction, ranges of porosity vary considerably due primarily to extreme variations in amounts of secondary cement. For instance, coarse-grained sandstones have greater permeability than finer ones when the same amount of cementing material is available to both. However, the same thickness of cement will form around the grains regardless of their size, therefore the smaller pore spaces, which occur in finer grained sandstones, will be cemented earliest.


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Basic Mud Logging V. Fossils and accessories Microfossils and some small macrofossils, or even fragments of fossils, are used for correlation and may also be environment indicators. For aiding in correlation, anyone making mud logs should familiarize himself with at least a few diagnostic fossils. The worldwide Cretaceous foraminiferal marker, Globotruncana, for example, should be in every surface data logger’s geologic “vocabulary.” Any surface data logger who examines samples should be able to distinguish such forms as foraminifera, ostracods, chara, bryozoa, corals, algae, crinoids, brachiopods, pelecypods, and gastropods so as to record their presence and relative abundance in the samples being examined. More detailed identification will probably have to be made by a paleontologist. Fossils may aid the surface data logger in judging what part of the cuttings is in place and what part is caved. For example, in the Gulf Coast region, fresh, shiny foraminifera, especially with buff or white color, are usually confined to the Tertiary beds; their occurrence in samples from any depth below the top of the Cretaceous is an indication of the presence of caved material. It would be helpful to each surface data logger to have available one or more slides or photographs illustrating the principal microfossils which might be expected to occur in each formation he will be logging. Even if the surface data logger cannot recognize the various fossils, it is important that he note them on the logs, noting also if there is an increase or decrease in the amount present in the samples. Foraminifera Accessory constituents, although constituting only a minor percentage of a rock, may be significant indicators of environment of deposition, as well as clues to correlation. The most common accessories are glauconite, pyrite, feldspar, mica, siderite, carbonized plant remains, heavy minerals, chert, and sand-sized rock fragments.

VI. Sedimentary structures Most sedimentary structures are not discernible in cuttings. On the other hand, one or more of them can always be found in any core, and they should be reported in the description thereof. Structures involve the relationship of masses or aggregates of rock components. They are conditioned by time and space changes; e.g., stratification may result from discrete vertical (time) change in composition, as well as changes in grain sizes or of fabric. In time of origin, they are formed either contemporaneously with deposition (syngenetic), or after deposition and burial (epigenetic). Syngenetic structures are often very important indicators of the environments of deposition of sediments.


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Basic Mud Logging VII. Porosity and permeability The detection and evaluation of porosity and the inferred presence or absence of permeability in the course of rock examination is one of the most important responsibilities of the surface data logger. Porosity is a measure of the volume of the void space in the rock; permeability is a measure of the capacity of a rock for transmitting a fluid. Permeability is dependent on the effective porosity and the mean size of the individual pores; it has a direct bearing on the amount of fluid recoverable, whereas porosity determines the amount that is present. Generally the smaller the grain or crystal size, the lower the permeability. When one discusses porosity and permeability in the oil fields, the primary concerns are the concepts of absolute and effective porosity. A reservoir will have a given amount of void space. If these voids are not connected, production will be limited. This “effective” porosity, in conjunction with permeability, dictates the ultimate quality of the reservoir. Porosity consists of primary and secondary forms. Primary porosity is formed when the sediment is originally deposited. Secondary porosity results from diagenesis by solution and replacement. Some clastic porosity forms from tectonic activity. The primary porosity in sandstones is principally interparticle (between the grains). Though not true theoretically, as a rule, the larger the grain size, the higher the porosity. This porosity will decrease during the formation of clays and alteration products after deposition. Compaction and cementation after deposition will also reduce the absolute porosity. Generally, porosity decreases as depth increases. However, cementation is the principal process leading to porosity loss in sandstones. There are three types of pore communication within clastics: 1. Catenary porosity - pores that have communication with others via two or more pore throats. 2. Cul-de-sac porosity - those that have communication via only one throat. 3. Closed pore communication. Types 1 and 2 make up “effective porosity”. Darcy's law for permeability is only valid when one fluid phase is present. When more than one fluid is present (the norm in any reservoir) the term effective permeability is sometimes used, meaning one rock may have three permeability values; effective permeability for oil, water and gas. Permeability can vary greatly depending on orientation (e.g. vertical permeability may be far lower than horizontal permeability) for the same rock, especially if micas are abundant. Permeability may also be strongly influenced by cross bedding and other sedimentary structures.

VIII. Hydrocarbon shows Although petrophysical analysis may give conclusive determination of the presence of commercial quantities of oil, it is the surface data logger’s responsibility to report and log all shows, and to see that good shows are evaluated. Positive indications of hydrocarbons in cuttings can be a decisive factor in the petrophysicist’s evaluation of a well. Unfortunately, no specific criteria can be established as positive indications of whether or not a show represents a potentially productive interval. The color and intensity of stain, fluorescence, cut, cut fluorescence and residual cut fluorescence will vary with the specific chemical, physical, and biologic properties of each hydrocarbon accumulation. PetroServices GmbH Training Center

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Basic Mud Logging The aging of the shows (highly volatile fractions dissipate quickly), and flushing by drilling fluids or in the course of sample washing, also tend to mask or eliminate evidence of hydrocarbons. The presence or absence of obvious shows cannot always be taken as conclusive. In many cases, the only suggestion of the presence of hydrocarbons may be positive cut fluorescence. In other cases, only one or two of the other tests may be positive. Hence, when the presence of hydrocarbons is suspected, it is very important that all aspects be considered: the porosity and thickness of the interval, the petrophysical evaluation, and the quality of the hydrocarbon tests. Listed below are some of the most common methods of testing for hydrocarbons in samples and cores that should be used by the surface data logger during routine sample examination.

Routine hydrocarbon detection methods:

1. Odor Odor may range from heavy, characteristic of low gravity oil, to light and penetrating, as for condensate. Some dry gases have no odor. Strength of odor depends on several factors, including the size of the sample. Describe as oil odor or condensate odor. Depending on the strength of odor detected, report as good, fair, or faint, in the remarks column. Faint odors may be detected more easily on a freshly broken surface or after confining the sample in a bottle for 15 to 20 minutes.

2. Staining and Bleeding The amount by which cuttings and cores will be flushed on their way to the surface is largely a function of their permeability. In very permeable rock, only very small amounts of oil are retained in the cuttings. Often bleeding oil and gas may be observed in cores, and sometimes in drill cuttings, from relatively tight formations. The amount of oil staining on ditch cuttings and cores is primarily a function of the distribution of the porosity and the oil distribution within the pores. The color of the stain is related to oil gravity; heavy oil stains tend to be dark brown, while light oil stains tend to be colorless. The color of the stain and bleeding oil should be reported. Ferruginous or other mineral stain may be recognized by lack of odor, fluorescence, or cut.

3. Reaction in Acid of Oil-Bearing Rock Fragments Dilute HCl may be used to detect oil shows in cuttings, even in samples that have been stored for many years. This is effected by immersing a small fragment of the rock to be tested (approximately 1/2 to 2 mm in diameter) in dilute HCl. If oil is present in the rock, surface tension will cause large bubbles to form, either from air in the pore spaces or from CO2 generated by the reaction of the acid with carbonate cement or matrix. In the case of calcareous rock, the reaction forms lasting iridescent bubbles large enough to raise the rock fragment off the bottom of the container in which the acid is held, and sometimes even large enough to carry the fragment to the surface of the acid before the bubbles break and the fragment sinks, only to be buoyed up again by new bubbles. The resulting bobbing effect is quite diagnostic. The bubbles which form on the surface of a cutting fragment of similar size which contains no oil do not become large enough to float the fragment before they break away, and the fragment, therefore, remains on the bottom. In the case of oil-bearing noncalcareous sandstone, large lasting bubbles form on the surface but may not float the fragment. The large bubbles result from the surface tension caused by the oil in the sample, which tends to form a tougher and more elastic bubble wall.


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Basic Mud Logging It should be pointed out that this test is very sensitive to the slightest amount of hydrocarbons, even such as found in carbonaceous shale; therefore, it is well to discount the importance of a positive test unless the bobbing effect is clearly evident or lasting iridescent bubbles are observed. The test is very useful, however, as a simple and rapid preliminary check for the presence of hydrocarbons. A positive oil-acid reaction alerts the observer to intervals worthy of more exhaustive testing.

4. Fluorescence Examination of mud, drill cuttings and cores for hydrocarbon fluorescence under ultraviolet light often indicates oil in small amounts, or oil of light color, which might not be detected by other means. All samples should be so examined. Color of fluorescence of crudes range from brown through green, gold, blue, yellow to white; in most instances, the heavier oils have darker fluorescence. Distribution may be even, spotted, or mottled, as for stain. The intensity range is bright dull, pale, and faint. Pinpoint fluorescence is associated with individual sand grains and may indicate condensate or gas. Mineral fluorescence, especially from shell fragments, may be mistaken for oil fluorescence, and is distinguished by adding a few drops of a solvent. Hydrocarbon fluorescence will appear to flow and diffuse in the solvent as the oil dissolves, whereas mineral fluorescence will remain undisturbed. When using the Sperry-Sun API gravity chart to determine the API gravity from the fluorescence, it must be taken from the unwashed cuttings mixed with water. By washing the drilled cuttings, some of the oil is washed from the cuttings, resulting in brighter and lighter color fluorescence than the actual formation. With sidewall cores and conventional cores, this problem is not as pronounced.

5. Reagent cut tests Oil stained samples that are old may not fluoresce; this failure to fluoresce should not be taken as decisive evidence of lack of hydrocarbons. All samples suspected of containing hydrocarbons should be treated with a reagent. The most common reagents used by the surface data logger are chlorothene, petroleum ether, and acetone. These reagents are available at most drug stores and give satisfactory results. The use of ether gives a more delicate test for soluble hydrocarbons than chlorothene or acetone, however, the ether being used should be tested constantly, for the least presence of any hydrocarbon product will contaminate the solvent and render it useless. Chlorothene is recommended for general use although it too may become contaminated after a long period of time. Acetone is a good solvent for heavy hydrocarbons but is not recommended for routine oil detection. Caution: Carbon tetrachloride is a cumulative poison and should not be used for any type of hydrocarbon detection. To test cuttings or cores, place a few chips in a white porcelain evaporating dish or spot plate and cover with reagent. The sample should be dried thoroughly at low temperature, otherwise water within the sample may prevent penetration by the reagents, thus obstructing decisive results. The hydrocarbon extracted by the reagent is called a “cut.” It is observed under normal light and should be described based on the shade of the coloration, which will range from dark brown to no visible tint. A faint “residual cut” is sometimes discernable only as an amber-colored ring left on the dish after complete evaporation of the reagent. A very faint cut will leave a very faint ring, and a negative cut will leave no visible color. The shade of the cut depends upon the gravity of the crude, the lightest crudes giving the palest cut, therefore, the relative darkness should not be taken as an indication of the amount of hydrocarbon present. A complete range of cut colors varies from colorless, pale straw, straw, dark straw, light amber, amber, very dark brown to dark brown opaque.


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Basic Mud Logging The most reliable test for hydrocarbons is the “cut fluorescence” or “wet cut” test. In this test, the effect of the reagent on the sample is observed under ultraviolet light, along with a sample of the pure solvent as control. The sample should be thoroughly dried before applying the reagent. If hydrocarbons are present, fluorescent “streamers” will be emitted from the sample and the test is evaluated by the intensity and color of these streamers. Some shows will not give a noticeable streaming effect but will leave a fluorescent ring or residue in the dish after the reagent has evaporated. This is termed a “residual cut.” It is recommended that the “cut fluorescence” test be made on all intervals in which there is even the slightest suspicion of the presence of hydrocarbons. Samples that may not give a positive cut or will not fluoresce may give a positive “cut fluorescence.” This is commonly true of the high gravity hydrocarbons that give a bright yellow “cut fluorescence.” Distillates show little or no fluorescence or cut but commonly give positive “cut fluorescence,” although numerous extractions may be required before it is apparent. Generally, low gravity oils will not fluoresce but will cut a very dark brown and their “cut fluorescence” may range from milky white to dark orange. An alternate method involves picking out a number of fragments and dropping them into a clear one or two ounce bottle. Petroleum ether, chlorothene, or acetone is poured in until the bottle is about half full. It is then stoppered and shaken. Any oil present in the sample is thus extracted and will color the solvent. When the color of the cut is very light, it may be necessary to hold the bottle against a white background to detect it. If there is only a slight cut, it may come to rest as a colored cap or meniscus on the top surface of the solvent. Caution: Proper ventilation is important when using petroleum ether as it may have a toxic effect in a confined space. In addition, petroleum ether and acetone are very inflammable and must be kept away from open flames.

6. Wettability Failure of samples to wet, or their tendency to float on water when immersed, is often an indication of the presence of oil. Under the microscope, a light-colored stain which cannot be definitely identified as an oil stain may be tested by letting one or two drops of water fall on the surface of the stained rock fragment. In the presence of oil, the water will not soak into the cutting or flow off its surface, but will stand on it or roll off it as spherical beads. Dry spots may appear on the sample when the water is poured off. This, however, is not useful in powdered (air drilled) samples, which, because of the particle size and surface tension effects, will not wet.

Other hydrocarbon detection methods  Acetone water test If the presence of oil or condensate is suspected, and provided no carbonaceous or lignitic matter is present in the rock sample, the acetone-water test may be tried. The rock is powdered and placed in a test tube and acetone is added. After shaking it vigorously it is filtered into another test tube and an excess of water is added. When hydrocarbons are present, they form a milky white dispersion, inasmuch as they are insoluble in water, whereas acetone and water are completely miscible.


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Basic Mud Logging  Hot water test Place 500 cc of fresh, unwashed cuttings in a tin or beaker, which has a capacity of 1,000 cc. Pour in hot water with a temperature of at least 170oF (77oC) until it covers the sample to a depth of 1 cm. Observe the oil film thus formed under ultraviolet light and record the amount of oil released.

 Pyrolysis test When well samples of kerogen-rich rock are pyrolyzed in a thick walled test tube placed over a propane torch, oily material may be generated and condensed as a brown residue around the walls of the tube. This simple technique may be used to identify source rocks capable of generating liquid oil. However, the pyrolysis technique cannot distinguish between oil source rocks and those sediments rich in humic matter (carbonaceous shales and coals) which are considered to be dominantly sources for gas. This test is also not responsive to post mature source rocks. The artificial test-tube generating process is believed to be similar to that associated with natural time-temperature dependent processes accompanying rock burial in depositional basins. Hydrocarbons in organic rich sediments may be determined semi-quantitatively with a Turner fluorometer. One hundred milligrams of rock is pyrolyzed as above and the resulting condensation is diluted with 3 milliliters of chlorothene. The fluorescence of the solution thus produced is recorded in fluorometer units.  Solid hydrocarbons and dead oil There has been much confusion, inconsistency and misunderstanding about the usage and meanings of these two terms. They are not synonymous. Solid hydrocarbons refer to hydrocarbons that are in a solid state at surface conditions, usually brittle, and often shiny and glossy in appearance. There are a wide variety of substances called solid hydrocarbons with variable chemical and physical properties. The most significant of these variations is that of maturity. Some solid hydrocarbons, like Gilsonite, are immature or barely mature oils, while others like anthraxolite represent the carbonaceous residue left after hydrocarbons have been overheated and thermally cracked. Anthraxolite is considered thermally dead oil. Gilsonite, on the other hand, is certainly not dead oil. It is a substance from which high-quality gasoline, industrial fuel oils and an endless list of other products are produced.


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Basic Mud Logging The term “dead oil” has been used indiscriminately in the industry to describe oils that are either (1) solid, (2) nonproducible or (3) immobile. All of these definitions are deceptive and misleading. Some solid hydrocarbons are not dead oil. Many so called “non-producible oils” are now productive because of improved recovery technology, and there are numerous examples of “immobile oil” at surface conditions that are fluid and mobile at depth. Other factors that have been used to distinguish them are extremely variable and have lacked general agreement by industry. For example, whether or not positive indications of fluorescence, residual cut, and/or cut fluorescence are considered requirements, or whether the physical state of the oil is solid or tarry. In view of the above it is recommended that usage of the term “dead oil” be applied only to thermally dead solid hydrocarbons that will not fluorescence, or give a cut or cut fluorescence. Whenever the term is used, qualifying data should be listed. IX. Procedures for rock and mineral identification  Tests with dilute HCl (10%) There are at least four types of observations to be made on the results of treatment with acid: 1. Degree of effervescence: limestone (calcite) reacts immediately and rapidly, dolomite slowly, unless in finely divided form (e.g., along a newly made scratch). While the effervescence test cannot yield the precision of chemical analysis or X-ray, it is generally adequate for routine examination. Unless the sample is clean, however, carbonate dust may give an immediate reaction that will stop quickly if the particle is dolomite. Impurities slow the reaction, but these can be detected in residues. Oil-stained limestones are often mistaken for dolomites because the oil coating the rock surface prevents acid from reacting immediately with CaCO3, and a delayed reaction occurs. The shape, porosity, and permeability will affect the degree of reaction because the greater the exposed surface, the more quickly will the reaction be completed. 2. Nature of residue: carbonate rocks may contain significant percentages of chert, anhydrite, sand, silt, or argillaceous materials that are not readily detected in the untreated rock fragments. Not all argillaceous material is dark colored, and unless an insoluble residue is obtained, light colored argillaceous material is generally missed. During the course of normal sample examination in carbonate sequences, determine the composition of the noncalcareous fraction by digesting one or more rock fragments in acid and estimate the percentage of insoluble residue. These residues may reveal the presence of significant accessory minerals that might otherwise be masked. 3. Oil reaction: if oil is present in cutting, large bubbles will form on a fragment when it is immersed in dilute acid. 4. Etching: etching a carbonate rock surface with acid yields valuable information concerning the texture, grain size, distribution and nature of noncarbonate minerals, and other lithologic features of the rock. Etching is accomplished by sawing or grinding a flat surface on a specimen, which is then submerged for a short time (10 to 30 seconds) in dilute acid with the flat surface parallel to the surface of the acid. After etching, the surface is carefully washed by gentle immersion in water, care being taken not to disturb the insoluble material adhering to the surface of the specimen. PetroServices GmbH Training Center

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Basic Mud Logging Limestone specimens etched in HCl usually develop and “acid polish.” Insoluble materials such as clay, silt, sand, chert, or anhydrite will stand out in relief against the soluble matrix. Dolomite crystals usually stand out also, inasmuch as they are attacked by the acid more slowly than is calcite. The internal structures of fossils, oolites, and detrital fragments are commonly revealed on an etched surface. If the appearance of the etched surface is so diagnostic that permanent record is desired, an acetate peel can be made, or the surface can be photographed.  Hardness Scratching the rock fragment surface is often an adequate way of distinguishing different lithic types. Silicates and silicified materials, for example, cannot be scratched, but instead will take a streak of metal from the point of a probe. Limestone and dolomite can be scratched readily, gypsum and anhydrite will be grooved, as will shale or bentonite. Weathered chert is often soft enough to be readily scratched, and its lack of reaction with acid will distinguish it from carbonates. Caution must be used with this test in determining whether the scratched material is actually the framework constituent or the cementing or matrix constituent. For example, silts will often scratch or groove, but examination under high magnification will usually show that the quartz grains have been pushed aside and are unscratched, and the groove was made in the softer matrix material.  Parting Shaly parting, although not a test, is an important rock character. The surface data logger should always distinguish between shale, which exhibits parting or fissility and mudstone, which yields fragments, which do not have parallel plane faces.  Slaking and swelling Marked slaking and swelling in water is characteristic of montmorillonites (a major constituent of bentonites) and distinguishes them from kaolins and illites.  Thin sections Certain features of rocks may not be distinguishable even under the most favorable conditions without the aid of thin sections. Thin sections adequate for routine examination can be prepared without the use of the refined techniques necessary to produce slides suitable for petrographic study. Some of the questions of interpretation which might be clarified by the use of thin sections include the following: mineral identification, grain-distribution, grain sizes, and source rock quality. Although wetting the surface of a carbonate rock with water, or mineral oil, permits “in depth” observation of the rock, some particles, or particle-matrix relationships still remain obscure until the rock is examined by transmitted light, plane and/or polarized. Once these features have been recognized in thin sections, they are frequently detectable in whole fragments, and only a few thin sections may be needed in the course of logging a particular interval. It is important to have polarizing equipment available for use in thin section examination - many features of the rock texture, and some minerals, are most readily recognized by the use of polarized light.


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Basic Mud Logging  Staining technique for carbonate rocks The distinction between calcite and dolomite is often quite important in studies of carbonate rocks. For many years, several organic and inorganic stains have been used for this purpose, but with varying degrees of success. One stain that is applicable to routine sample examination and is both simple and rapid is Alizarin Red S. This stain can be used on any type of rock specimen, and it has proved especially useful in the examination of cuttings. The reactions to acid of chips of dolomitic limestone or calcareous dolomite are often misleading, and the rapid examination of etched chips does not always clearly show the calcite and dolomite relationships. Alizarin Red S shows clearly the mineral distribution. Calcite takes on a deep red color; other minerals are uncolored.  Insoluble residues Carbonate rocks may contain significant percentages of chert, anhydrite, sand, silt, or argillaceous materials that are not readily detected in the untreated rock fragments. The study of cherts and associated residues has been a common practice for many years in certain areas. For routine logging of micro-insoluble residues, symbols for accessory minerals, should be used.  Versenate analysis Versenate analysis is a relatively fast and inexpensive method for determining quantitatively the calcite/dolomite ratios of given carbonate rocks. The method has shown merit in the mapping of intimately associated limestone and dolomite. It is based on the color reactions of a reagent on crushed and sieved carbonate samples.  Heavy mineral studies Heavy mineral studies are used today primarily when a geologist is seeking information concerning the source areas and distribution patterns of siliciclastic sediments. Their use as a correlation tool is limited.

 Test for specific rocks and minerals Many of the more perplexing problems of rock and mineral identification can be solved by use the thin sections. However, certain simple and rapid tests are discussed as follows. Clay: Shales and clay occur in a broad spectrum of colors, mineral composition, and textures. Generally, their identification is done with ease; however, light colored clay is commonly mistaken for finely divided anhydrite. The two may be distinguished by a simple test. Anhydrite: will dissolve in hot dilute hydrochloric acid and, when cooled, will recrystallize out of solution as acicular needles. Clay remains insoluble in the hot dilute acid. Chert: Recognition of the more common varieties of chert and siliceous carbonates generally is not a problem. Weathered chert, however, is often found to be soft enough to be readily scratched and mistaken for clay or carbonate. Lack of reaction with acid generally distinguishes this type of chert from carbonates.


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Basic Mud Logging Clay and tripolitic chert may require petrographic techniques for differentiation. In thin sections under polarized light, chert commonly has a characteristic honey-brown color. Evaporites: Anhydrite and gypsum are usually readily detected in cuttings. Anhydrite is more commonly associated with dolomites than with limestones, and is much more abundant in the subsurface than gypsum. At present, there appears to be little reason to distinguish anhydrite from gypsum in samples. Anhydrite is generally harder and has a pseudo-cubic cleavage; the cleavage flakes of gypsum have “swallow-tail” twins. Anhydrite can be readily recognized in thin sections by its pseudo-cubic cleavage, and under polarized light, by its bright interference colors. The dilute hydrochloric acid test is a valid and simple test for anhydrite or gypsum in cuttings. Place the cuttings in a watch glass and cover with acid. Heat on a hot plate to ±250oF (±120oC) and wait for the sample to start dissolving. If anhydrite or gypsum is present, acicular gypsum crystals will form around the edge of the acid solution as it evaporates. If the sample contains much carbonate, a calcium chloride paste may form and obscure the acicular gypsum crystals. Dilute the residue with water, extract and discard the solution and report the test. Salts are rarely found at the surface and generally do not occur in well samples. Unless a salt-saturated or oil-base mud is used, salt fragments or crystals dissolve before reaching the surface. The best criteria for detecting a salt section are: (a) The occurrence of “salt hoppers” (b) Marked increase in salinity of the drilling mud (c) A sudden influx of abundant caved material in the samples (d) A sharp increase in the drilling penetration rate (e) Mechanical log character, particularly the sonic, density, and caliper log. Cores are the most direct method of determining whether salt is present, but they are not usually cut in salt sections. Salts are commonly associated with cyclical carbonate sections and massive red bed sequences. In the former, they are usually thin bedded and often occur above anhydrite beds. Potassium-rich salts, the last phase of an evaporation cycle, are characterized by their high response on gamma ray log curves. Phosphate: Place on the suspected mineral (either on the hand specimen or on an uncovered thin section) a small crystal of pure white ammonium molybdate. Allow one or two drops of dilute nitric acid to fall on the crystal. If the rock contains phosphate, the crystal rapidly takes on a bright yellow color. Siderite: Siderite is usually readily distinguished by its characteristic brown color and slow rate of effervescence with dilute HCl. The mineral often occurs as buckshot-sized pellets. The presence of siderite or iron dolomite in the same rock with calcite may be difficult to recognize and the following stain procedure is recommended for use when such cases are suspected. The polished face of the chip is immersed for 5 to 10 minutes in a hot, concentrated solution of caustic potash to which a little hydrogen peroxide is added at intervals during treatment. The surface is finally washed and dried in the air. Siderite is stained brown while ferrous dolomite (ankerite) takes a weaker stain and ordinary dolomite remains colorless; calcite is roughened but is not destroyed and chamosite retains it green color unless carbonate of iron is present. This method is equally applicable to powders.


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Basic Mud Logging Feldspar: The presence, quantity and type of feldspar constituents can be important in the study of reservoir parameters in some sandstones, particularly the coarse arkosic sands or “granite washes.” Staining techniques, operationally applicable to rather large etched core (or surface) sample surfaces, allows a better estimation of the amount and distribution of feldspar grains. The use of sections to make these estimates is expensive, and often difficult because of the small surfaces provided. Bituminous rocks: Dark shales and carbonates may contain organic matter in the form of kerogen or bitumen. Carbonates and shales in which the presence of bituminous matter is suspected should be examined by thin section and pyrolysis-fluorometer methods for possible source rock qualities. Dark, bituminous shales have a characteristic chocolate brown streak, which is very distinctive.

Problems in interpreting drill cuttings Cavings Cavings may often be recognized as material identical to what has already been seen from much higher in the hole. This spalling of previously penetrated rocks into the ascending mud stream is particularly pronounced after trips of the drill stem for bit changes, drill stem tests, coring operations or other rig activities. It is suppressed by good mud control, but most samples will contain caved material. (Soft shales, thinly bedded brittle shales, and bentonites cave readily and may be found in samples representing depths hundreds of feet below the normal stratigraphic position of those rocks.) Owing to differences in the hardness of rocks, the type and condition of the bit, and the practice of the driller, one cannot set any hard and fast rule for the size of true cuttings. Caved fragments tend to be larger than fragments of rock from the bottom of the hole, and they are typically rounded by abrasion. Flaky shape, freshness of appearance, sharp edges and signs of grinding by the bit may be used as criteria for the recognition of fresh cuttings. Recirculation Recirculation chiefly refers to sand grains and microfossils from previously drilled rocks which re-enter the hole with the mud stream and contaminate the rising sample. Lost circulation material A large variety of substances may be introduced into the hole to combat lost circulation difficulties. These include such obviously foreign materials as feathers, leather, burlap sacking, or cotton seed hulls, as well as cellophane (which might be mistaken for selenite or muscovite), perlite, and coarse mica flakes which might be erroneously interpreted as formation cuttings. Most of these extraneous materials will float to the top of the sample tray when it is immersed in water, and so can be separated and discarded at once. Other substance may need more careful observation. Generally the sudden appearance of a flood of fresh-looking material which occupies the greater part of a sample is enough to put the sample logger on his guard. As a check, he can consult the well record for lost circulation troubles, and the kinds of materials introduced into the hole.


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Basic Mud Logging Cement Cement fragments in cuttings are easily mistaken for sandy, silty, or chalky carbonate. However, most cements are of an unusual texture or color, frequently have a glazed surface, tend to turn yellow or brown when immersed in dilute HCl, and are usually full of fine black specks. The latter are sometimes magnetic, in which case the fragments of cement can be removed from the cuttings with the aid of a small magnet. Drilling mud In examining unwashed or poorly washed cuttings, it is often important to be able to recognize the drilling muds which were used. An inexperienced surface data logger may confuse drilling mud with soft clay, bentonite, or sometimes gypsum or a carbonate. Thorough washing and rinsing in a pan of water will generally remove most mud contamination. If necessary, lithic fragments can be broken open to see if the interior (fresh) differs from the surface (coated). Oil-base and oil-emulsion muds coat the cuttings with oil, and care must be taken to distinguish such occurrences from formation oil. They are generally recognized because they coat all cuttings regardless of lithology, rather than being confined to one rock type. Such contamination can sometimes be removed by washing the samples with a detergent or with dilute HCl. Ligno-sulfate muds may present problems in samples used in palynological studies. Oil contamination, pipe dope, etc. Foreign substances, such as pipe dope or grease, from the rig operations sometimes enter the mud stream. Most pipe dope and grease will normally appear in the cuttings after a trip out of and into the hole has been made. Usually these contaminations will disappear after one or two complete circulations are made. Pipe scale, bit shavings, and casing shavings Scale shavings of metal may also contaminate the samples, but they can be readily removed with a small magnet. They are usually rusty and rarely present a logging problem. Bit shavings are shiny as opposed to pipe scale. Casing shaving will also be very shiny and the shape will usually be curved or spiral. The drilling foreman on location should be notified immediately when bit or casing shavings are found in a sample. Miscellaneous contaminants Other lithic materials which may be present in cuttings samples and obscure their real nature, or might be logged as being in place, include rock fragments used as aggregate in casing shoes.


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Basic Mud Logging Miscellaneous interpretation problems  Rock dust If samples are not washed sufficiently, a fine dust composed of powdered rock or dried drilling mud may cover the chips with a tightly adhering coat. In such cases, care should be taken that a fresh surface of the rock is described. Wetting the samples will tend to remove this coating, but if the chips are saturated with oil, the powder may still adhere to the surface even after immersion in water, unless a wetting agent or ordinary household detergent is used. These comments are particularly applicable to limestone and dolomite where the powdered rock film tends to be in the form of crystals, which may mask the true texture of the rock. In this case, the best procedure is to break a few chips and obtain fresh surfaces for description.  Powdering (bit spin and percussion chalkification) Powdering is the pulverization of the cuttings by regrinding (failure of the mud to remove cuttings from below the bit), or by crushing between the drill pipe and the wall of the borehole. It can result in the disappearance of cuttings from some intervals, and the erroneous logging of chalky limestone where none exists.  Fusing Shales drilled by a diamond bit may be burned and fused, resulting in the formation of dark gray or black hard fragments that resemble igneous rock.  Air gas drilling samples Cuttings from wells drilled with air or gas instead of mud are usually made up of small chips and powder, which makes sample examination difficult. Often a sample screening of the cuttings to eliminate the powder will facilitate the sample study. When the cuttings are entirely of powder, little can be done beyond describing basic rock types and colors. When the cuttings are carbonates, the basic rock type will be difficult to determine because dolomite powder effervesces as readily as limestone powder. Where well-indurated shale sections are air drilled, the samples can be cleaned conveniently by washing them with care on a 60- to 100-mesh screen. This cleaning procedure should be required, where feasible, as the dust coating on the particles will mask the true color, texture and even the basic lithology of the drilled section. When “mist” drilling is done, particles can become plastered with fine mud which is removable only by a washing process; simple screening does not suffice.  Spread Spread is the separation of large from small cuttings by relative slippage (also called elutriation or differential settling) in the mud stream, so that the cuttings of a rock drilled up into fine chips may overtake the cuttings of a rock drilled up into coarse chips during their journey up the borehole. This results in the wrong sequence of rock types or very mixed sample being recovered.


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Basic Mud Logging Geological notes Unconformities Notation on a sample log of any data, which suggest the presence of an unconformity, is important, even though the evidence is inconclusive. Supporting evidence may be found in nearby wells. In cuttings, the following criteria may indicate the presence of an unconformity: 1. Concentrations of minerals, e.g., phosphate, pyrite, glauconite, calcite, manganese nodules. 2. Abrupt changes in mineral assemblages, fauna, lithologic character, or cementing material. 3. Iron oxide stains or manganese coatings. 4. Corrosion surfaces, as developed on conglomerates (e.g., blackened limestone pebbles). 5. Desert varnish, as polished surfaces on pebbles. 6. Basal conglomerate - generally more heterogeneous and weathered than other conglomerates. 7. Bone and tooth conglomerate - accumulated as a “lag zone” overlying an unconformity. 8. Siliceous shells with beekite rings - small, bluish grey to white doughnut-like rings occurring on siliceous shells below some unconformities. 9. Weathered chert - a definite indication of an unconformity, providing the chert is residual and not reworked. 10. Asphaltic residues can be present at unconformities at which oil seeped out to the surface. In the case of cherts, the oil or asphaltic residue may be in the residual chert and not in the overlying reworked material. 11. Porous zones in limestone, caused by solution by ground water, may be evidence of unconformities, but porous zones can develop for considerable distances below the surface. The porosity may not be in contact with the unconformity, but the erosional interval is the cause of it. Limestones that underlie unconformities should be more deeply leached than similar limestones, which do not underlie conformities. Other porous zones may occur at unconformities in various types of lithology because of the occurrence there of coarser material and the effects of weathering. An unconformity so established may be traced from well to well by recognition of the porous zones. 12. Caliche and vadose pisolites, may form in carbonate rocks exposed to surface weathering. The presence of two or more associated criteria greatly increases the chances that an unconformity is present. Environments Environments of deposition may be interpreted from (1) geometry and distribution of depositional units, (2) sedimentary structures and lithologic associations, (3) fossil assemblages. Information from drill cuttings, excepting fossil assemblages, is often insufficient to allow interpretation of environments. When a number of control wells are available in a region and sedimentary units can be traced, it is often possible to interpret at least generalized environments on geometry and distribution of units, lithologic associations, and in some cases, electric log shapes. Sedimentary structures and fossils observed in slabbed cores are the principal physical basis for identifying specific sedimentary environments, and determining sediment genesis.


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Basic Mud Logging Environments are classified with respect to sea level: continental, coastal, marine; and on the basis of physiography: shelf, slope, and basin. Clastic sediments are controlled by the source of transported materials and the currents, which disperse them; therefore, it is necessary to distinguish between coastal and continental environments in order to differentiate sand bodies, which were formed by different processes, and so have very different shapes and characters. The physiographic distinction between shelf and basin is important to the understanding of sandstones, which may have been deposited in submarine fans and canyons. Carbonate sediments are generally best understood in terms of physiography. Tabular units may be expected to be present on the shelf, and lenticular units, such as mounds or reefs, form at the loci of major changes in slope; e.g., the shelf margin. The constituents of carbonate sediments are usually generated locally and not derived from external sources as are those of siliciclastics, so they may be found to change character abruptly in response to inherited or constructed topographic features anywhere in shallow marine environments. The distinction between continental, coastal, and marine is of lesser importance; most genetic units in carbonates are marine, although the landward limits of carbonate deposits may be within the coastal realm. Carbonates formed under subaerial conditions in a continental environment may not be volumetrically important but they demand particular attention as indicators of periods of exposure and thus of the intensive diagenesis which may occur under such conditions. Description and logging of drilled cuttings and cores is an essential step in providing data, which will contribute to the interpretation of the environment of deposition and genesis of a sedimentary unit. Environmental interpretation from cuttings is extremely difficult and more often than not is impossible. However, in certain exploration areas even gross designations of basin, shelf, or continental is useful information. More specific environmental interpretations can be very helpful in establishing local facies variations and sedimentologic sequences and should be recorded on the sample log along with qualifying data.


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MUD LOGGING EQUIPMENTS & SENSORS Our work at the site is supported by the latest in mud logging equipment and technology, which are second to none. Our mission is our mission to provide the most accurate, timely and useful mud logging data available, and to work diligently to attain a high level of client satisfaction on every well. The logging unit is an information hub at the well site, which brings information on the drilling process in real time to the decision makers (on site, or at any remote location). The equipments and sensors that supports the job are as follow:

DATA ACQUISITION SYSTEM Petroservices has many systems for data acquisition that guaranty accurate and reliable real time data acquisitions, among these systems are the followings:

1. DAQ TVR 60-8A: DAQ TVR60-8A is a fast and reliable data acquisition unit that is designed to support: • • • • • • • • • • • • • • • • • • •

DAQ TVR60-8A supports up to 60 analog input channels, 8 digital input channels and one up/down counter for draw work. Analog to digital conversion of slowly changing positive current signals on 60 current channels. Measuring of angular move of two-phase draw works revolutions sensor (DL 100A or analogues) and conversion of the obtained values into current or voltage. Measuring of frequency on eight channels (pulse/sec) with further conversion of the obtained values into current or voltage. Definition of conditions on eight channels. Closing/unclosing of normally open “dry” contacts on eight channels. Power supply to sensors (barriers) + 24V. Digital data transfer to the unit computer (Com 3) via RS-422/485 interface in conformity with the exchange protocol. Digital data transfer to the unit computer (Com 4) via RS-422/485 interface and power supply to Rig Monitor + 24V. Manual entry of traveling block position. Manual entry of calibration parameters for traveling block. Manual entry of type of outgoing analog signal (current or voltage). Manual entry of digital output channels. Manual entry of output values of analog channels. Monitoring of traveling block position. Monitoring of frequency values on channels. Monitoring of conditions values on channels. Monitoring of digital (out) channels. Monitoring of output values in analog channels.

Data acquisition unit “DAQ TVR 60-8A” is equipped with the keyboard beeper and a password protection against unauthorized change of data. For more detailed information about DAQ TRV 60-8A refers to PetroServices mud logging instrumentation manual. PetroServices GmbH Training Center

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Basic Mud Logging 2. Philips Transokomp 350: Today many data acquisition networks are increasingly being linked together. More than ever before, large volume, high speed, and accurate, easy-to-use communication functions are essential in many disciplines. In the world of measurement and control where the number of measurement points has increased sharply, the ability to acquire information from a large number of points easily and economically is crucial. Interfacing to a personal computer allows simplified utilization of the information while improving quality and efficiency. Philips TK 350 is based on a unique, new concept to meet these needs. The art of measurement is revolutionized by Philips TK 350, which integrates functions of conventional recording and data logging. Philips Transokomp 350 multi channels computerized recorder can record and measure from small-scale 10-ch data up to widely distributed 300-ch multi-point data. The number of measurement points can be expanded up to a maximum of 300-ch by connecting up to six subunits (DS400/DS600) to a main unit (DR232/242). Using dedicated extension cables between units, interconnections can be extended up to 500 m. Since measured objects scattered over a wide area can be wired fast and with a minimum of wiring, a flexible, extensive measurement system can be configured. The input modules to be incorporated in the Philips TK 350 can be selected from the following, to suit your measurement conditions: • mA-input Module This module can directly measure DC currents ranging from -20 mA to 20 mA since it contains shunt resistors. It cannot be connected to a system's main unit. • Alarm module This module can output alarm signals as contact signals. The module can be connected to the main unit or the subunit. • DI/DO module This module allows a signal to be output in the case of alarm, failure, or chart end and a remote control signal for the product to be input. The module can be connected to the main unit or the subunit but only one module in all units. • Communication interface module This module is necessary when communicating with a personal computer. Measurement conditions can be set and data acquired via the communication interface (GP-IB, RS-232-C, etc.). This module can only be connected to the main unit.


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Basic Mud Logging 3. Siemens SIREC D400: Siemens SIREC D400 is a chartless high-end display recorder in 300 mm x 300 mm format with 12.1" Color- TFT-Display that supports 16 up to 48 analog channels and up to 48 digital channels. Display: With more than 256,000 colors makes it easy to interpret process data and take action with the intuitive bar charts, digital values, trends or customized displays. The heavy duty durable touch screen provides easy data entry and rapid navigation though the menus. The touch screen operator interface provides fast, easy access to the recorder menus making set up and data analysis quick and efficient Data storage: On-board non-volatile memory - up to 1850 Mega Byte in addition to removable Compact flash and USB storage with no moving parts all solid- state data storage. Data export: Removable compact flash and USB flash storage device provides multiple data storage alternatives. Data is stored in a secure binary encrypted format, with the recorder’s configurations, providing added security of the data files. Soft alarms: 6 "software" alarms per pen are easily set up to display and record selected out-of-limit conditions. These can be tied to the relay or digital outputs to activate the user’s external equipment. Independent display chart speeds and logging rates: Logging rates can be programmed completely separate from the chart display speed, allowing the data to be displayed and stored at the rates that best suits the application. Fuzzy logging: This standard feature provides a unique method to increase the storage capacity of the recorder. The data is monitored to determine changes in process data; if no changes are observed data is logged periodically. If data is changing rapidly, it is recorded normally at the programmed rate. By not logging data that is static, data compression of up to 100:1 or more can be achieved saving valuable memory. Pulse inputs: The 8 Digital I/O option card has 4 channels that can be set as pulse inputs (first 4 channels). The operating frequency for pulse inputs on the Digital I/O card is 1 kHz max. Communications: The recorder supports FTP, Mod bus TCP/IP (slave mode), Web and Email over Ethernet (DHCP standard) communications port and Modbus RTU (slave mode) via an RS485 port. USB ports allow the use of an ASCII barcode reader. Email sent to your network connected PC triggered by an Alarm or an Event. Data security: Total data integrity: Data is stored in secure encrypted files making it easy to retrieve the data dependent on process information. Data is automatically recognized without having to remember file names. Password protection: Up to 4 levels of password protection with up to 50 different users are available. Multiple level of password protection and an audit trail of actions enhance the security of the data.


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Basic Mud Logging 4. Petroservices DAQ: This DAQ is mainly an electronic board that implements the functions of a complete data acquisition system. This PCB can deal with the following inputs: • • • •

36 analog channels “4-20mA” 4 analog channels “0-10V {1ch.}, 0-15V {1ch.} and 0-5V {2ch.}” 8 frequency channels “0-1 KHz” 4 up/down counter channels

All the inputs are connected to PCB via 3 flat cables “1 for digital inputs and 2 for analog inputs” The PCB is connected to computer by a USB cable “male/male” and transmits all data to computer using the software included with DAQ. The output from the PCB also includes: •

Analog output {0-5V} for all frequency channels “to be connected to a chart recorder or any analog input control system” Analog output {0-5V} for all up/down counters “to be connected to a chart recorder or any analog input control system”

•

Technical specifications: • • • • •

Supply voltage DC Power Consumption Interface between PCB and computer Max. Input frequency “Freq. channels” Operation temperature


: 5V “from USB or external power supply” : max. 7.5 VA : USB cable “male/male” : 1kHz : 10° - 50°C

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GAS SYSTEM As the drill bit breaks loose the formation, cuttings and gas in the formation are transferred to and entrained in the drilling mud and transported to the surface. With this in mind, the surface data logger hypothesizes the existence of a direct relationship between the kind and amount of gas and/or oil in the drilling mud arriving at the surface, and the gas and/or oil that was in place in the formation being drilled at the time that particular mud was passing by the bit at the bottom of the hole. The gas system is one of the most important systems in oil and gas drilling operations as accurate and fast gas readings can be used as a good tool for reservoir evaluations. The main components of the gas system are:  The gas trap, which is the device for removing gases from the drilling mud.  Flow control panel that controls the flow of the gases come into the mud logging unit and those pumped out of the mud logging unit.  The gas detectors proper (Total gas detector and gas chromatograph). These detectors are the flame ionization detectors (FID).  H2S and CO2 detectors. Before we discuss the different parts of the gas system it is good to know the different types of gasses that might exists during the different drilling operations, which are classified as follow: Background gas: Under normal drilling conditions, it is quite common for a relatively small amount of gas to be continuously in evidence. This “background gas” can originate from a previously drilled section, which contained a show and which bleeds a small amount of gas into the mud. Normally, gas can be contained in the formation being drilled of very low proportions, i.e., shales are often found to contain gas but due to their extremely low porosity and permeability characteristics. Background gas is often methane only with little or no heavy gases. However, continuously high levels of background gas often indicate that the well is being drilled very close to balance and may indicate that a higher mud weight is required. Connection gas: Also involved when the bit is raised off bottom is the gas due to swabbing even with short distances such as those encountered when making a connection and due to the lowering of the hydrostatic pressure from the loss of ECD (equivalent circulating density) when the mud pumps are shut down for a connection or check for flow. Therefore, this connection gas is used as a helpful guide towards determining how near the hydrostatic pressure is to a balance condition. Connection gas can be identified by the occurrence of gas peaks observed on the recorders. These “bumps” in the recorder trace will be separated by the time between each connection and will arrive on the surface near lagged depth of the connection depth. When connection gases are in evidence a similar phenomenon may be observed whenever the drill string is pulled off bottom and the pumps are shut down. This method may also be used to simulate a connection gas peak to help in determining the balance condition. As with background gas and trip gas, connection gas is a strong indicator of a balanced drilling condition. Trip gas: It is normal for an increase in the gas readings to occur after a trip has been made. This occurrence is commonly referred to as “trip gas.” To understand the presence of trip gas, it is necessary to visualize what happens as the old bit is pulled out of the hole, for it is during this operation that the gas which is subsequently labeled “trip gas” gains entry into the mud PetroServices GmbH Training Center

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Basic Mud Logging system. Not only does the bit have the largest diameter of all tools in the hole, it also, naturally, is at the extreme lower end of the drill string. In the process of “coming out of the hole,” the bit is being pulled through a mud filled cylinder of a diameter of only slightly greater than the bit itself. As the bit is pulled through this cylinder formed by the hole wall, a swabbing action on the formation takes place. The drilling fluid is, therefore, forced to rush pass the bit to its underside, and there is a momentary reduction in hydrostatic pressure immediately adjacent to and below the bit as it is travelling upward. As the bit travels up the hole past sections containing gas, those of sufficient pressure will bleed into the adjacent mud column when the hydrostatic pressure is reduced by the swabbing action of the bit. Once this gas has entered, it is entrained by the mud and remains static in the mud until the trip is completed. When the trip is completed and the bit is near bottom and circulation resumes, this gas interval is pumped to the surface where the gas is detected as trip gas. Trip gas is recognized as that increase in mud gas which often appears on the gas detector sometime between the time drilling is resumed and the time the first sample from the newly drilled formation is at the surface. Usually trip gas will appear toward the end of this period, just before the first newly drilled sample is due. Contamination gas: Occasionally drilling operations require the introduction of oil in various forms to provide additional pipe lubrication, etc. Oil based muds are often used to minimize formation damage through elimination of excessive water loss. Diesel is the normal oil phase used in inverted oil emulsion muds. Diesel in its natural state does not contain volatile hydrocarbons and therefore is not disruptive to gas detection equipment. However, diesel is often transported in containers, which have previously carried volatile crudes and may therefore retain some volatile gases. Hydrogen gas is often detected in pipe iron or associated with the setting action of cement. Occasionally mud additives or various chemical reactions in the mud will provide other hydrocarbons or combustible gases, which may be detectable by wellsite total gas detectors

1. Gas trap: The gas readings from the drilling mud as related to fluids and gases in-place in the formation must be interpreted with the following consideration in mind: The extraction of this gas from the drilling mud must be done in a manner that is independent of variables such as density, viscosity and gel strength of the mud; in a manner independent of the flow rate of the mud through the whole mud system; in a manner so that all the gases as completely possible may be extracted even from a high gel strength mud, and in a manner which would be considered reliable around drilling rig conditions which tend to be destructive of sensitive equipment. PetroServices currently uses two types of gas traps. These are air powered and electrically powered. In operation, the bottom of the trap lies submerged about two inches under the surface of the returning mud stream. The mud, tending to seek its own level, flows in the inlet in the bottom of the trap canister. Rotation of the motor-driven impeller blade causes this mud to whirled around rapidly. PetroServices GmbH Training Center

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Basic Mud Logging The centrifugal force of this whirling action causes the level of the mud to be raised around its periphery inside the canister until it flows out the discharge on the side of the trap. The depth to which the trap is lowered into the mud should be adjusted to give a continuous sample of 3 gallons per minute of mud flowing through the trap.

2. Flow control panel: Flow control panel is manufactured by Petroservices GmbH to control the flow of all gasses coming in (or out) to (or from) the unit concerning gas detection devices. The panel consists of the followings: • • • • • • • •

Suction pump: that sucks the gasses Solenoid valve: 3-way valve to control the back flush operation Suction valve with buzzer alarm: Raises the alarm when gas line is clogged Manometers: controls the flow of gas sample to each detector “CHR, TG, H2S and CO2” Gauges with adjusting knobs: to adjust the pressure of gas sample Position Switches: To switch between pump and back flush positions To switch between calibration bottles used To open or close a path for gas sample Filter: filtrates the sample from moisture Power supply “Siemens”: to feed the pump, solenoid valve and buzzer

It now becomes apparent that a reliable gas detecting technique demands that the number of influencing variables be kept in control. Ideally, only the amount of gas in the mud and its corresponding reading should be variable. For this reason, it is important that the trap consistently pump a constant volume of mud, that the amount of air drawn through the trap be maintained at a constant, that there be no leaks or restrictions in the flow system. With Petroservices flow control panel the undesired variables that might affect gas readings are minimized to very negligible values that add more accuracy to hydrocarbon gas evaluations.

PetroServices Flow Control Panel


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Basic Mud Logging 3. Hydrogen generator: The gas generator will produce a constant stream of hydrogen at a pre-determined pressure and flow rate when connected to a suitable power supply and fed with a suitable quality of deionized water. These units are suitable for use in laboratories and light industrial environments and are non-hazardous for transportation purposes. Hydrogen generators are safe. Hydrogen is produced on demand. No high pressure storage as with gas cylinders. Any malfunction or hydrogen leaks inside or outside the generator are immediately indicated on the alphanumeric display with an audible alarm. If the alarm condition is not rectified, the generator automatically shuts down. Hydrogen generators are coupled with an external water tank to allow continuous supply of pure hydrogen. No maintenance on the electrolyser, no need to replenish or add any electrolyte. The patented Multi Layer Electrodes electrolytic cell is tolerant to light water impurities and does not require deionizer bags, neither any inlet filters on the water reservoir. The final dryer is made of stainless steel instead of plastic material, to avoid pollutants to get in contact with the high purity hydrogen. Working principle: Hydrogen is produced through a patented MLE electrolytic cell. Demineralized water is loaded into the cell from a small water tank. The patented cell electrolysis the water producing hydrogen. Oxygen is than safely dissipated into the atmosphere. Hydrogen flows through a UHP filter.

Hydrogen generator

4. Hydrocarbon gas system: The gas system is designed to provide a continuous reading of total hydrocarbons in a gas stream, while periodically performing a chromatographic separation of the sample to determine the composition of the sample gas stream. This is accomplished using a 10 port gas sampling valve with a 25μL sample loop in a thermostatted valve oven, a 1m (3’) Hayesep-D packed column in a temperature programmable column oven, a total gas detector, an FID detector and a built-in air compressor. This gas system can be modified to incorporate a second FID instead of the total hydrocarbon gas detector. Speciation of C1-C6 hydrocarbons is handled by the gas sampling valve, Hayesep-D column, and FID while the total gas detector provides continuous, total hydrocarbon monitoring. Detection limits for this system are 0.1% to 100% for the continuous total hydrocarbon monitor, and 0.005% to 100% for speciated hydrocarbons using the FID. The built-in peak simple data system displays both the continuous total hydrocarbon reading, using the data logger mode, and the separated peaks. When the system receives out of range readings, an alarm function may alert the user.


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Basic Mud Logging Theory of operation: The sample gas stream is connected to a bulkhead fitting on the system’s thermostatted valve oven where it flows through the sampling loop of the 10 port gas sampling valve, and also to the total gas detector. The fitting labeled “Sample In” close to the valve oven is the sample gas stream inlet. The user must regulate the pressure of the sample stream so that it enters this inlet at 10psi. The instrument is factory preset to deliver 5mL/min to the total gas detector at 10psi. The remainder of the flow, approximately 100mL/min, passes through the sample loop. This relatively high flow rate gets the sample from the sampling point into the gas chromatograph with minimal delay. Once the sample enters the inlet, its path is T’d through two restrictors and on to the detectors. To avoid damaging the total gas detector, the maximum pure hydrocarbon flow to reach this detector is 5mL/ min. The restrictors regulate the flow to the total gas detector to 5mL/min when the sample inlet pressure is 10psi. The remainder of the sample stream (approximately 100mL/min) flows through the gas sampling valve’s loop and is periodically injected into the Hayesep-D column, then detected by the FID. At an automatically repeating time interval controlled by the user with the built-in peak simple data system, the gas sampling valve injects the contents of its sample loop into the Hayesep-D packed column where it is separated into the constituent hydrocarbon (C1-C6) peaks and detected by the FID detector. Between automatic sample injections into the column, the 10 port gas sampling valve is in “load” position (top right schematic). In this position, the carrier gas flows into the column while sample gas flows through the 25μL sample loop and to vent. When peak simple automatically moves the valve to the “inject” position (bottom right schematic), the carrier gas flows though the sample loop first, then sweeps the sample into the Hayesep-D column. The SRI 410 front panel has 15 control zones. Each control zone has three black push buttons and one led status indicator, arranged in columns across the front control panel. The SRI 410 has three gas pressure (EPC) control zones, seven detector parameter control zones (FID ignitor, PID lamp current, etc), and five temperature control zones. Each control zone is adjusted by a trimpot, located on the front edge of the top panel (immediately behind the front control panel). To adjust the local set point, press that button and turn the trimpot while observing the led display until the desired set point appears. Ensure that the display select switch is on “all buttons”.


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Basic Mud Logging 4. H2S gas system: Statox 501 is a fixed gas detection system for toxic and combustible gases. The DIN–rail mounted modern controller saves space, money and installation time. One safe controller for all gases; any combination of a sensor head plus a controller is a complete gas detection system. This is what makes the Statox 501 so safe and reliable. The Statox 501 also gives you the opportunity to alter or expand existing systems with minimum expenditure. Programs for any gas and measuring range are permanently stored in the memory of the controller. The user-friendly software program allows authorized personnel to select different configurations by a simple push of a button. The controller power supply and common alarm module clip on to a DIN rail. The remote sensor heads and any alarm or recording devices connect to terminals on the front of the controller. The Statox 501 controller has three relays for alarm 1 and 2 system failure (115 / 230 V AC / 2 A). An analog output for recorder or process control systems is also included. Measured values are displayed on a 4 digit LED-display. It is easy to program or calibrate the new 501 controller! Just follow the menu! If sensor heads are to be installed in division 1 areas, they can be connected via intrinsically safe repeaters. The 24 V power supply as well as the signals for the common alarm module are transmitted via bus from one controller to the next. All terminals are easily accessible from the front. Compur manufactures electrochemical sensors for the detection of oxygen deficiency and toxic gases. These sensors generate an electrical current proportional to the actual gas concentration. The remote sensor heads are designed as intrinsically safe certified 4 - 20 mA transmitters and have an integrated concentration display. Combustible gases are detected with a variety of catalytic beads (pellistors). These sensor heads are certified and can be connected directly to the controller even if they are to be used in classified areas. The controller can supply and operate different designs of catalytic sensors. With so many possibilities, the system can easily be tailored to suit your individual application needs.

5. CO2 gas detector: Dräger Polytron IR CO2 is a gas detector for continuous monitoring of carbon dioxide. It offers all benefits of fail-safe IR measurement technology for applications in rough environments. The transmitter uses microprocessor technology to convert the signal to a 4-20 mA analog output. The unit is designed for one-man calibration and offers a variety of diagnostics and self test features. The configuration and calibration of the transmitter is menu guided and easy to perform, using the built-in push buttons. With the ATEX-approval (device category II 2G acc. to 94/9/EC) the Dräger Polytron IR CO2 is suitable for use in potentially explosive atmospheres zone 1 and zone 2.


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RIG SENSORS 1. Draw work sensor: An optical shaft encoder is attached to the draw works drum shaft. The encoder provides better than 0.25 degrees resolution of the rotation of the drawworks, which in the worst case scenario gives a 1cm resolution of the block position. The depth processing unit (Motrona) determines the absolute position of the hook taking into account the number of wrap turns on the drum and the cable position. The sensor is used to detect the kelly position and the direction of the Kelly (up or down), Petroservices fabricates draw work inductive sensors using two inductive proximity switches to detect the moving of the iron gear which is installed directly on the draw work shaft. The draw work gear has a specific numbers of teeth and the inductive proximity switches detect the gear movement in which direction and how many teeth moved from the previous position. Draw work sensor is a four wires sensor; every two wires are supplied by 8VDC and send the detection as pulses to the depth processing unit to process the signal of the two proximity switches.

In Motrona depth processing unit the counting inputs A and B are designed for input frequencies up to 100 kHz (with all counter modes) and up to 25 kHz (with all other operating modes). The minimum pulse duration on the Reset input must be 500 μsec. (maximum frequency 1 kHz) All inputs are designed to receive impulses from an electronic impulse source. Where exceptionally you need to use mechanical contacts, please connect an external capacitor between GND (-) and the corresponding input (+). With a capacity of 10 μF, the maximum input frequency will reduce to 20 Hz and miscounting due to contact bouncing will be eliminated. A voltage output is available, operating in a range of 0~+10 V or –10 V~+10 V according to setting. At the same time, a current output 0/4 – 20 mA is available. Both outputs refer to the GND potential and the signal polarity changes with the sign in the display. The outputs provide a 14 bits resolution and the response time to changes of the measuring value is approximately 0.7 msec. PetroServices GmbH Training Center

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Basic Mud Logging 2. Hook load sensor: The hook load sensor is a line tension transducer provides a 4-20 mA loop powered electrical signal output proportional to a wire rope's single line load up to 100,000 lbs. (45360 kg) max. The system consists of • An aluminum block with internally sealed strain gages and electronic signal conditioning circuitry. • Deflection plates. • A center clamping mechanism. Features of the TCE-100K • Accepts wire-rope diameters from 7/8 to 2 inches (22.2 to 50.8 mm) without requiring modification. • Light weight “17 pounds (7.7 kg)”. • Low maintenance. • High accuracy with better than 2% repeatability. Principle of operation The transducer is clamped to the anchored wire rope (deadline). Because of the transducer's geometry, the wire line is bent or deflected by 1/4 inch (6.35 mm) at the center of the transducer body when properly installed. When additional load is applied to the wire rope, the wire rope tends to straighten at the deflection point; it therefore exerts an outward force on the yoke. This force is transmitted through the clamping mechanism, with reaction forces at the deflection blocks to the transducer body. These combined forces create a strain on the transducer body, which the strain gauge detects, the strain gauge bridge and the signal conditioner combine to produce a 4-20 mA output signal proportional to the tension in the wire rope.

3. Pressure sensor: The PTX 661 hammer union pressure transmitter has been designed for use in extremely harsh environments in both on-shore and offshore oil drilling operations where high shock and vibration is likely to be encountered. The transmitter is available in both the 1502 and 2202 WECO® wing union configurations, both of which are NACE sour gas compatible. The PTX 661 differs from other hammer union pressure transmitters in that it has a replaceable pressure transmitter insert, which substantially reduces the high cost of transmitter replacement. With a 2 kHz response time, the device is suitable for measuring static and dynamic mud pressure. The PTX 661 incorporates Druck's proprietary high-accuracy silicon sensor with up to 2.5 times better accuracy than many competitive devices. The low volume oil fill technology allows response times of faster than 2 kHz. The field-proven 4 to 20 mA electronics, packaged in a rugged enclosure, provide power supply regulation, reverse polarity, overvoltage and EMC protection. The fully encapsulated design provides exceptional reliability in high shock and vibration environments.


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Basic Mud Logging Technical specifications: • Operating Pressure Ranges: 0 to 5000, 6000, 10,000 and 15,000 psi (0 to 350, 410, 700 and 1000 bar) • Overpressure: 2X FS to a maximum of 20,000 psi • Pressure Containment: 30,000 psi (2070 bar) maximum • Supply Voltage: 10 to 28 VDC • Output Current: 4 to 20 mA (Two-wire configuration) • Zero Setting: ±1% FS @ 75°F (24°C) • Span Setting: ±0.5% FS @ 75°F (24°C) • Weight: 6 lb (2.72 kg) nominal • Response Time: Faster than 0.5 msec. (2 kHz) VEGA pressure sensor Another type of pressure sensors is VEGABAR, which is a pressure transmitter for measurement of gauge pressure and absolute pressure. Measured products are gases, vapours and liquids. The front flush versions are also suitable for use in viscous or contaminated products. Advantages Small, compact dimensions Stainless steel housing with cable outlet Zero and span adjustable Deviation < 0.5 % Wetted parts of stainless steel Function The process pressure causes a resistance change in the sensor element via the stainless steel diaphragm. This change is converted into an appropriate output signal and outputted as measured value. With measuring ranges up to 16 bars, a piezoresistive sensor element with internal transmission liquid is used. From 25 bars, a strain gauge sensor element is used on the rear of the stainless steel diaphragm. This dry system operates without additional isolating liquid. Technical specifications • Output signal: 4-20 mA • Supply voltage: 12 -28 VDC • Safety barrier: STAHL 9160 • No. of wires: 2 wires


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Basic Mud Logging 4. Rotary speed (RPM) sensor: Rotary speed TURCK proximity sensors are entirely solid state electronic controls that contain no moving parts to wear out as do mechanical switches. They require no physical contact for actuation, no cams or linkages, have no contacts to bounce or arc and are completely encapsulated, making them impervious to most liquids, chemicals and corrosive agents. In addition, TURCK sensors can be used in hazardous explosive environments without any special enclosures. RPM sensor is used to count the number of rotations of the drill pipes per minute. It gives very important information accompanied with rotary torque about the drilled formations and drill string condition. Technical specifications: • No. of wires: • Safety barrier: • Operating voltage: • Hysteresis (differential travel): • Nominal voltage for IS sensors: • Time delay before availability: • Polarity inversion protection: • Wire break protection: • Protection against transients: • Operating temperature: • Enclosure: • Sensing range • Switching frequency: • Repeatability

2 wires 9350/10 STAHL 5 – 15 VDC 1 – 10% (5% typical) 8.2 VDC -/< 2 ms Available Available Available -25'c to +70'c (-13'f to +158t) meets NEMA 1. 3, 4, 6. 13 and IEC ip67 10 mm = 0.157” (nominal) up to 500 Hz -/< 2% of nominal sensing range

Frequency converter: The two wires rotary speed sensor is connected to Pepperl+Fuchs KFU8-FSSP-1.D frequency converter unit. The frequency voltage/current converter KFU8FSSP-1.D is a device for indication and monitoring of periodical signals which occur in almost all areas of process automation, i. e. from frequencies in general and speeds in specific. The input signal sequence is evaluated and converted into a frequency by a µ-controller in accordance with the cycle method. The µ-controller calculates a voltage or current proportional to the input frequency and produces it with a digital analog converter in respect to the selected measurement range’s limit value. The following analogue signals can be selected: (0 V ~ 10 V, 2 V ~ 10 V, 0 mA ~ 20 mA, 4 mA ~ 20 mA). PetroServices GmbH Training Center

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Basic Mud Logging 5. Rotary torque sensor: The clamp meter rotary torque sensor provides a solution to measure the rotary torque on electric rigs in an accurate, simple, and reliable way proving itself over the years in hundreds of installations worldwide. The system displays torque in foot-pounds, amps or metric equivalents with simple Installation procedure. The split core transducer is clamped around the power cable that leads to your rig’s electric motor. This will enable the transducer to sense the current that the motor draws, which is proportional to that required by the rotary table, and transmits the signal to the dual output signal conditioner. The conditioner will then convert this signal to an accurate reading on the electric meter. This dual output signal conditioner will also drive the multipoint data recorder or data acquisition system. Features: • Simple, no moving parts to wear out. • Split core transducer measuring electrical current to the motor clamps around power cable; no shunts or direct electrical connections required. • Signal conditioner unit provides outputs to meters, recorders, and other data acquisition devices. • Multi-scaled meter provides readings for different gear selections. Technical specifications: • No. of wires: • Power supply: • Measuring range: • Max. temperature:

4 wires 15VDC 0 to 1000 A AC&DC 70° c

6. Pump stroke sensor: Pump stroke sensors are heavy duty, Telemecanique XCK-J precision industrial limit switches designed to meet international standards. The pump stroke sensors are used for counting the number of strokes of the mud pumps that sucks the mud from active tanks and pumps it into the drilling pipes; the number of strokes is very important to calculate the mud flow and numbers of bbl that are pumped into the well. The mechanical switches (limit switches) are fixed on the pump latch beside the pump movement part. Each limit switch has two connections (NC) normally closed and (NO) normally open you can connect the supply wires (signal wires) in one of them but it is better to connect it on (NO). The pump stroke sensor is fixed by L-shape holder its length can be changed easily and the holder is fixed to the pump body by J-clamp. PetroServices GmbH Training Center

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Basic Mud Logging Frequency converter: The two wires pump stroke sensor is connected to Pepperl+Fuchs KFU8-FSSP-1.D frequency converter unit. The frequency voltage/current converter KFU8FSSP-1.D is a device for indication and monitoring of periodical signals which occur in almost all areas of process automation, i. e. from frequencies in general and speeds in specific. The input signal sequence is evaluated and converted into a frequency by a µ-controller in accordance with the cycle method. The µ-controller calculates a voltage or current proportional to the input frequency and produces it with a digital analog converter in respect to the selected measurement range’s limit value. The following analogue signals can be selected: (0 V ~ 10 V, 2 V ~ 10 V, 0 mA ~ 20 mA, 4 mA ~ 20 mA). The software provides number of strokes per minute for each pump, total Strokes for each pump and total strokes for all pumps and they are all can be monitored in digital and graphical formats.

7. Pit level sensor: Ultrasonic probe sensors are used for pit level measurement. The Probe is an ultrasonic level monitor combining sensor and electronics in a single package. It is designed to measure liquid levels in closed vessels. The mud pit level measuring device monitors single pit level and the total pit volume through a non contact measuring principal for continuous level measurement with ultrasonic pulses. The probe emits a series of ultrasonic pulses from the transducer. Each pulse is reflected as an echo from the material and sensed by the transducer. The echo is processed by The Probe using Milltronic's proven `Sonic Intelligence' techniques. Filtering is applied to help discriminate between the true echo from the material and false echoes from acoustical and electrical noises and agitator blades in motion. The time for the pulse to travel to the material and back is temperature compensated and then converted into distance for display, mA output and relay actuation. Ultrasonic probe Technical specifications: • Power: 18 to 30 V DC, 0.2 A max • Environmental: indoor / outdoor • Altitude: 2000 m max. • Ambient Temperature: -40 to 60 °C (-40 to 140 °F) • Range: 0.25 to 5 m (0.8 to 16.4 ft.), liquids only (standard 24 V model, black label) 0.25 to 8 m (0.8 to 26.2 ft.), (Extended Range model, green label)


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Basic Mud Logging 8. Mud flow sensors: Paddle mud flow sensor: Mud flow sensor is a paddle type sensor that monitors mud flow through the return line. The sensor is mounted on the return line with the paddle extending into the mud flow. Deflected by the force of the mud flow, the paddle uses a Hall Effect sensor with a variable target to produce a 4 to 20 MA analog output that is proportional in amplitude to the position of the paddle. This current output can be used to monitor, display and record mud flow information. The Mud Flow Sensor has sealed oil impregnated bushings for reliable operation, an adjustable paddle arm for fitting to various sizes of flow lines. Non-linear and logarithmic calibrations through the computer allow accurate calibrations to be made for most installations over a wide range of flows. Depending on the instrumentation setup, the actual readings (in gal/min, lit/min) can be installed and calibrated through online system software. This sensor is very simple in construction and electrical principle: Mechanical idea: a paddle is put against the flow of the mud and connected through gears to heavy weight to resist the flow. Electrical idea: 1 kΩ variable resistance connected series with 150Ω resistance connected mechanically with the paddle gear to change this resistance. Technical specifications: • No. of wires: 2 wires • Output signal: 4-20 mA • Power supply: 24 VDC Electromagnetic mud flow sensor: Magnetic flow meters, or magmeters, are intended to measure the flow of electrically conductive liquids in full pipes. The pressure drop through the meter is minimal, (equal in magnitude to a piece of pipe of the same diameter and length) making it an excellent choice for low pressure systems. There are no moving parts or obstructions in the fluid stream so the meter is virtually maintenance free and suitable for fluids containing abrasives. Modern pulsed DC excitation eliminates problems with zero shift often found in other designs. The detection of flow is accomplished using the principle of electromagnetic induction. As a conductor passes through a magnetic field, a voltage is generated that is proportional to the velocity of the conductor moving through the field. In the case of the magnetic flow meter, the conductor is a conducting liquid. The higher the flow rate the greater the generated voltage. PetroServices GmbH Training Center

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Basic Mud Logging 9. Mud weight sensor: The measuring theory of mud weight sensor is to measure the differential pressure between two pressure sensors that are immersed in mud with fixed distance between them. The two pressure sensors dive with different depths into the mud, the upper sensor needs a minimum depth of 5-10 cm from the mud surface, the distance between the two sensors is about 30 cm; with less distance, the accuracy will be lesser, with more distance, the accuracy will be better. The sensors will give via galvanic isolators the difference between two signals to the differential amplifier. The difference between two signals is resulted from the difference in pressure exerted on the two sensors, not the depth to which the sensors dive in mud. The differential amplifier type KFDS2-CR-1.300, send an output of 4-20 mA signal to the analog to digital converter. The Sensor has a small ceramic diaphragm and can be delivered with a built-in temperature probe. The galvanic isolator KFD2-CR-1.300 has an Input/output for 0-20 mA on below 1K Ohm. The sensors and isolators are ATEX Certified. Technical specifications: • Sensor type: • Power supply: • Pressure rang: • No. of wires: • Signal type: • Output signal:

LGC-KSR1D-12AN-Ex 15~24 VDC 0-0.4 bar 4 wires sensor Analog 4-20 mA

10. Mud temperature sensor: The temperature PT-100 sensor is a platinum resistance thermometer (PRT) which offers high accuracy over a wide temperature range (from -200 to 400 °C). The temperature sensor consists of the Fourier systems adaptor and a platinum resistance thermometer (PT-100). Due to the sensor's wide range (-200 °C to 400 °C), it can be used as a thermometer for experiments in chemistry, physics, biology, earth science, environmental science and is mostly suitable for water and other chemical solution temperature measurements. The PT-100 sensor is mostly used for industrial applications, where the high precision of the PT-100 is required. In scientific fields, the PT-100 sensor is used mostly for the research of extremely low temperatures. Due to its low temperature measurement response and high accuracy, this is a very powerful sensor for monitoring liquid gases and other materials.


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Basic Mud Logging The principle of operation is to measure the resistance of a platinum element; platinum resistance thermometers use electrical resistance and require a small electric current of 1.7 mA to operate, supplied by the Fourier system adaptor. The resistance ideally varies linearly with temperature; the platinum resistance thermometer (PT-100) has a resistance of 100 Ohms at 0°C and 138.4 Ohms at 100 °C. The output signal range of 4-20 mA is accepted by the data logger analog to digital converter then the temperature is calculated & recorded in the data logger’s memory. Technical specifications: • No. of wires: • Signal type: • Output signal: • Power supply: • Accuracy:

2 wires sensor Analog 4-20 mA 15-24 VDC ±2 % over entire range

11. Mud conductivity sensor: The Emerson toroidal (inductive) conductivity sensors consist of a pair of wire-wound metal toroids over molded with corrosion resistant PEEK or Tefzel. One coil is the transmitter, and the other coil is the receiver. When the sensor is immersed in a conductive liquid and the transmitter coil is energized, the coil induces a current in the solution. The solution current induces another current in the receiver coil, which the analyzer measures. The current in the receiver coil is directly proportional to the conductivity of the solution. Toroidal sensors are ideal for highly conductive liquids, up to 2 S/cm (2,000,000 uS/cm). The minimum conductivity depends on the size of the toroids and the number of windings in each toroid. Generally, the minimum conductivity is between 50 and 500 uS/cm. The measurement is not sensitive to flow rate or direction of flow. The hole through the toroids must remain open. The toroidal conductivity sensor has a rigid construction that stands up to high vibration applications such as drilling mud shaker trays. A single piece 304 SS tube supports the toroid coils and reinforces the threaded mounting shaft. This subassembly is then over molded in chemically resistant plastic. There are no seams or welds to crack and cause leakage and subsequent failure. The toroidal sensor transmitter is connected with the sensor so that you can apply sensor calibration and setup through this transmitter unit shown in the right figure. Technical specifications: • Power supply: • Output signal: • Range: • Maximum temperature: • Maximum pressure: • Integral cable length: • Weight/shipping weight: • EX – certificate:


+ 24 VDC 4 to 20 mA 200 micro s / cm - 1000 ms/cm 120 C 295 psig 20 ft (6.1 m) 1.2 kg/ 2 kg without holder EEX IB IIC T4

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GEOLOGICAL EQUIPMENTS 1. Binocular microscope: The optical microscope, often referred to as the "light microscope", is a type of microscope, which uses visible light and a system of lenses to magnify images of small samples. Optical microscopes are the oldest and simplest of the microscopes. Digital microscopes are now available which use a digital camera to examine a sample, and the image is shown directly on a computer screen without the need for optics such as eyepieces. All optical microscopes share the same basic components: •

•

•

•

The eyepiece - A cylinder containing two or more lenses to bring the image to focus for the eye. The eyepiece is inserted into the top end of the body tube. Eyepieces are interchangeable and many different eyepieces can be inserted with different degrees of magnification. Typical magnification values for eyepieces include 5x, 10x and 20x. The objective lens - a cylinder containing one or more lenses typically made of glass, to collect light from the sample. At the lower end of the microscope tube, one or more objective lenses are screwed into a circular nose piece, which may be rotated to select the required objective lens. Typical magnification values of objective lenses are 4x, 5x, 10x, 20x, 40x, 50x and 100x. Some high performance objective lenses may require matched eyepieces to deliver the best optical performance. The stage - a platform below the objective which supports the specimen being viewed The stage usually has arms to hold slides (rectangular glass plates with typical dimensions of 25 mm by 75 mm, on which the specimen is mounted). The illumination source - below the stage, light is provided and controlled in a variety of ways. At its simplest, daylight is directed via a mirror. Most microscopes, however, have their own controllable light source that is focused through an optical device called a condenser, with diaphragms and filters available to manage the quality and intensity of the light.

The whole of the optical assembly is attached to a rigid arm, which in turn is attached to a robust U shaped foot to provide the necessary rigidity. The arm is usually able to pivot on its joint with the foot to allow the viewing angle to be adjusted. Mounted on the arm are controls for focusing, typically a large knurled wheel to adjust coarse focus, together with a smaller knurled wheel to control fine focus. Stereo microscope: The stereo or dissecting microscope is designed differently from the diagrams above, and serves a different purpose. It uses two separate optical paths with two objectives and two eyepieces to provide slightly different viewing angles to the left and right eyes. In this way, it produces a three-dimensional visualization of the sample being examined. Digital microscope: Low power microscopy is also possible with digital microscopes, with a camera attached directly to the USB port of a computer, so that the images are shown directly on the monitor. Often called "USB" microscopes, they offer high magnifications (up to about 200×) without the need to use eyepieces, and at very low cost. The precise magnification is determined by the working distance between the camera and the object, and good supports are needed to control the image. The images can be recorded and stored in the normal way on the computer. The camera is usually fitted with a light source, although extra sources (such as a fiber-optic light) can be used to highlight features of interest in the object. PetroServices GmbH Training Center

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Digital microscope

Modern stereo microscope optical design

2. UV-box: UV-box is a tool used by well site geologists to examine different cutting samples under ultraviolet light for the existence of oil in these samples. Fluorescence is the emission of electromagnetic radiation light by a substance that has absorbed radiation of a different wavelength. In most cases, absorption of light of a certain wavelength induces the emission of light with a larger wavelength (and lower energy). The most striking examples of this phenomenon occur when the absorbed photon is in the ultraviolet region of the spectrum, and is thus invisible, and the emitted light is in the visible region. Practical applications of this effect are found in the UV-box. A simple chemical test may be carried out to determine whether fluorescence in drill cuttings is a result of oil or some fluorescing mineral. This is easily and quickly established by immersing some of the drill cuttings in a petroleum solvent (chlorothene, trichlorothene, ether, or acetone). If the fluorescence is derived from mineral sources, the minerals will not dissolve in the solvent and the solvent will remain colorless under ultraviolet light. However, if hydrocarbons are present in the rock, they will disseminate into the solvent, giving the entire solvent a distinctive color under ultraviolet light. This sheen under UV light is called cut and the color of the cut indicates the quality of the oil. Pale blue-white is high gravity (light) oil, yellow is medium gravity, and orange brown for low gravity (heavy) oil.

CN-6 UV cabinet

The CN-6 UV cabinet welcome one or two hand held UV lamps (VL-6 model) in any of the three following wave lengths: 254, 365 or 312 nm. PetroServices GmbH Training Center

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Basic Mud Logging 3. Shale density balance: KERN sensitive balance is used to precisely determine the weight of small samples not more than “200 gm”. It is used in Petroservices mud logging unit in weighing crushed cutting samples that are going to be tested for calcimetry and in shale density measurements. These electronic scales are a precision instrument. Electromagnetic fields can cause major display discrepancies. The scales must then be repositioned away from electromagnetic fields. All sources of environmental interference, such as drafts and vibrations, should be avoided. Sudden changes of temperature should be avoided. The scales must be reset to match changes in temperature. The scales are not hermetically sealed; therefore avoid high humidity, steam and dust. Do not bring liquids into direct contact with the scales, as these can penetrate into the measuring mechanism. Cleaning material should only be dry or barely damp. Do not use solvents as these can damage paintwork or other plastic parts. Remove damaged items immediately from the scales. The measuring mechanism will be stabilized by allowing the scales to warm up for a few minutes after switching them on. Place items to be weighed carefully on the scales. Do not place objects on the weighing platform for any period, apart from normal use. Sudden shocks or overloading the scales beyond the maximum permitted weight should absolutely be avoided, balance could be damaged.

4. Calcigraph: Calcigraph is used to determine the amount of calcium carbonate and magnesium carbonate in a sample of alkaline earth carbonates such as oil well cores or drilled cuttings. Calcite builds up in drilling fluids and in water, treatment processes causes scaling problems. Data from the Calcigraph can help determine the proper chemical treatment. In calcigraph, calcium carbonate and magnesium carbonate are reacted with 10 percent hydrochloric acid in a sealed reaction cell to form CO2. As the CO2 is released, the pressure build up is measured using either a pressure gauge or a pressure recorder. During the calibration process, a calibration curve is created by reacting HCl with pure, reagent grade CaCO3. By using a known weight of CaCO3 reagent, you can determine the relationship between the amount of pressure released and the weight of CaCO3 in the sample. Since all reaction cells are slightly different, this relationship will be different for each cell. Therefore, a calibration curve is required to obtain accurate results.


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GLOSSARY A Abandon v: to cease producing oil and gas from a well when it becomes unprofitable. A wildcat well may be abandoned after it has proven nonproductive. Several steps are involved in abandoning a well: part of the casing is removed and salvaged; one or more cement plugs are placed in the borehole to prevent migration of fluids between the different formations penetrated by the borehole; and the well is abandoned. In many states, it is necessary to secure permission from official agencies before a well may be abandoned. Absolute permeability n: a measure of the ability of a single fluid (as water, gas, or oil) to flow through a rock formation when the formation is totally filled (saturated) with the single fluid. The permeability measure of a rock filled with a single fluid is different from the permeability measure of the same rock filled with two or more fluids. Acid fracture v: to part or open fractures in productive, hard-limestone formations by using a combination of oil and acid or water and acid under high pressure. Acidize v: to treat oil-bearing limestone or other formations, using a chemical reaction with acid, to increase production. Hydrochloric or other acid is injected into the formation under pressure. The acid etches the rock, enlarging the pore spaces and passages through which the reservoir fluids flow. The acid is held under pressure for a period of time and then pumped out, and the well is swabbed and put back into production. Chemical inhibitors combined with the acid prevent corrosion of the pipe. Adjustable choke n: a choke in which a conical needle and seat vary the rate of flow. Air actuated adj.: powered by compressed air, as the clutch and brake system in drilling equipment. Air drilling n: a method of rotary drilling that uses compressed air as the circulation medium. The conventional method of removing cuttings from the wellbore is to use a flow of water or drilling mud. Compressed air removes the cuttings with equal or greater efficiency. The rate of penetration is usually increased considerably when air drilling is used. However, a principal problem in air drilling is the penetration of formations containing water, since the entry of water into the system reduces the ability of the air to remove the cuttings. American Petroleum Institute n: 1. founded in 1920, this national oil trade organization is the leading standardizing organization on oil field drilling and producing equipment. It maintains departments of transportation, refining, and marketing in Washington, D.C., and a department of production in Dallas. 2. (slang) indicative of a job being properly or thoroughly done (as, “His work is strictly API”). 3. degrees API, used to designate API gravity. Angle of deflection n: in directional drilling, the angle, expressed in degrees, at which a well is deflected from the vertical by a whip stock or other deflecting tool. Annular blowout preventer n: a large valve, usually installed above the ram preventers, that forms a seal in the annular space between the pipe and wellbore or, if no pipe is present, on the wellbore itself. Annular space n: 1. the space surrounding a cylindrical object within a cylinder. 2. the space around a pipe in a wellbore, the outer wall of which may be the wall of either the borehole or the casing; sometimes termed the annulus. PetroServices GmbH Training Center

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Basic Mud Logging Anticline n: an arched, inverted-trough configuration of folded and stratified rock layers. API abbr: American Petroleum Institute. API gravity n: the measure of the density or gravity of liquid petroleum products in the United States derived from specific gravity in accordance with the following equation: API gravity = 141.5/ specific gravity - 131.5 API gravity is expressed in degrees, a specific gravity of 1.0 being equivalent to 10o API.

B Back off v: to unscrew one threaded piece (as a section of pipe) from another. Back up v: to hold one section of an object (as pipe) while another is being screwed into or out of it. Bail n: a cylindrical steel bar (similar to the handle or bail of a bucket, only much larger) that supports the swivel and connects it to the hook. Sometimes, the two cylindrical bars that support the elevators and attach them to the hook are called bails. v: to recover bottom hole fluids, samples, or drill cuttings by lowering a cylindrical vessel called a bailer to the bottom of a well, filling it and retrieving it. Bailer n: a long cylindrical container, fitted with a valve at its lower end, used to remove water, sand, mud or oil from a well. Bailing line n: cable attached to the bailer, passed over a sheave at the top of the derrick, and spooled on a reel. Barge n: any one of many types of flat-decked, shallow draft vessels, usually towed by a boat. A complete drilling rig may be assembled on a drilling barge, which usually is submersible; that is, it has a submersible hull or base that is flooded with water at the drilling site. Drilling equipment, crew quarters, and so forth are mounted on a superstructure above the water level. Barite n: barium sulfate BaSO4; a mineral used to increase the weight of drilling mud. Its specific gravity is 4.2 (i.e., it is 4.2 times heavier than water). Barium sulfate n: 1. a chemical combination of barium, sulfur, and oxygen. Also called barite. 2. a tenacious scale that is very difficult to remove. Barrel n: a measure of volume for petroleum products. One barrel is the equivalent of 42 U.S. gallons or 0.15899 cubic meters. One cubic meter equals 6.2897 barrels. Basket sub n: a fishing accessory run above a bit or mill to recover small pieces of metal or junk in a well. Bed n: a specific layer of earth or rock in contrast to other layers of different material lying above, below, or adjacent to it. Belt n: a flexible band or cord connecting and passing about each of two or more pulleys to transmit power or impart motion.


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Basic Mud Logging Bit n: the cutting or boring element used in drilling oil and gas wells. The bit consists of the cutting element and the circulating element. The circulating element permits the passage of drilling fluid and utilizes the hydraulic force of the fluid stream to improve drilling rates. In rotary drilling, several drill collars are joined at the bottom end of the drill string. The bit is attached to the end of the drill collar. Most bits used in rotary drilling are roller cone bits. Bit breaker n: a heavy plate that fits in the rotary table and hold the drill bit while it is being made up in or broken out of the drill string. Bit record n: a report on each bit used in a drilling operation that lists the bit type, the amount of footage the bit has drilled, and the nature of the formation penetrated. Blind ram n: an integral part of a blowout preventer that serves as the closing element. Its ends do not fit around the drill pipe but seal against each other and shut off the space below completely. Block n: any assembly of pulleys on a common framework; in mechanics one or more pulleys, or sheaves, mounted to rotate on a common axis. The crown block is an assembly of sheaves mounted on beams at the top of the derrick. The drill line is reeved over the sheaves of the crown block alternately with the sheaves of the traveling block, which is hoisted and lowered in the derrick by the drill line. When the elevators are attached to a hook on the traveling block, and when drill pipe is latched in the elevators, the pipe can be raised or lowered in the derrick. Blooey line n: the discharge pipe from a well being drilled by air drilling. The blooey line is used to conduct the air or gas used for circulation away from the rig to reduce the fire hazard as well as to transport the cuttings a suitable distance from the well. Blowout n: an uncontrolled flow of gas, oil, or other well fluids into the atmosphere. A blowout, or gusher, occurs when formation pressure exceeds the pressure applied to it by the column of drilling fluid. A kick warns of an impending blowout. Blowout preventer n: one of several valves installed at the wellhead to prevent the escape of pressure either in the annular space between the casing and drill pipe or in open hole (i.e., hole with no drill pipe) during drilling or completion operations. Blowout preventers on land rigs are located beneath the rig at the land’s surface; on jackup or platform rigs; they are located at the water’s surface; and on floating offshore rig, on the seafloor. Boll-weevil n: (slang) an inexperienced rig or oil-field worker, sometimes shortened to “weevil.” Bomb n: a thick-walled container, usually steel, used to hold sample of oil or gas under pressure. Bond n: the state of one material adhering or being joined to another material (as cement to formation). v: to adhere or be joined to another material. BOP abbr: blowout preventer. Borehole n: the wellbore; the hole made by drilling or boring. Bottom hole n: the lowest or deepest part of a well. adj: pertaining to the bottom of the wellbore.


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Basic Mud Logging Bottom hole choke n: a device with a restricted opening placed in the lower end of the tubing to control the rate of flow. Bottom hole pressure n: 1. the pressure at the bottom of a borehole. It is caused by the hydrostatic pressure of the drilling fluid in the hole and, sometimes, any back pressure held at the surface as when the well is shut in with blowout preventers. When mud is being circulated, bottom hole pressure is the hydrostatic pressure plus the remaining circulating pressure required to move the mud up the annulus. 2. The pressure in a well at a point opposite the producing formation, as recorded by a bottom hole pressure bomb. Box n: the female section of a tool joint. Brake n: a device for arresting the motion of a mechanism, usually by means of friction, as in the draw works brake. Break out v: 1. to unscrew one section of pipe from another section, especially drill pipe while it is being withdrawn from the wellbore. During this operation, the tongs are used to start the unscrewing operation. See tongs. 2. to separate, as gas from liquid. Breakout cat-head n: a device attached to the shaft of the draw works that is used as a power source for unscrewing drill pipe; usually located opposite the driller’s side of the draw works. Breakout tongs n: tongs that are used to start unscrewing one section of pipe from another section, especially drill pipe coming out of the hole. Also called lead tongs. Bring in a well v: to complete a well and put it in producing status. Buck up v: to tighten up a threaded connection (as two joints of drill pipe). Bullet perforator n: a tubular device that, when lowered to a selected depth within a well, fires bullets through the casing to provide hole through which the well fluids may enter.

C Cable n: a rope of wire, hemp, or other strong fibers. Cable tool drilling n: a drilling method in which the hole is drilled by dropping a sharply pointed bit on the bottom of the hole. The bit is attached to a cable, and the cable is picked up and dropped, picked up and dropped, repeatedly, as the hole is drilled. Cap rock n: 1. impermeable rock overlying an oil or gas reservoir that tends to prevent migration of oil or gas out of the reservoir. 2. the porous and permeable strata overlying salt domes that may serve as the reservoir rock. Cased adj: pertaining to a wellbore in which casing is run and cemented. Cased hole n: a wellbore in which casing has been run. Casing n: steel pipe placed in an oil or gas well as drilling progresses to prevent the wall of the hole from caving in during drilling and to provide means of extracting petroleum if the well is productive.


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Basic Mud Logging Casing centralizer n: a device secured around the casing at regular intervals to center it in the hole. Casing that is centralized allows a more uniform cement sheath to form around the pipe. Casing coupling n: a tubular section of pipe that is threaded inside and used to connect two joints of casing. Casing head n: a heavy steel, flanged fitting that connects to the first string of casing and provides housing for the slips and packing assemblies by which intermediate strings of casing are suspended and the annulus sealed off. Also called a spool. Casing shoe n: also called a guide shoe. Casing string n: the entire length of all the joints of casing run in a well. Casing is manufactured in lengths of about 30 feet, each length or joint being joined to another as casing is run in a well. Catch samples v: to obtain cuttings for geological information as formation are penetrated by the bit. The samples are obtained from drilling fluid as it emerges from the wellbore or, in cable-tool drilling, from the bailer. Cuttings are carefully washed until they are free of foreign matter, dried, and labeled to indicate the depth at which they were obtained. Cat-head n: a spool-shaped attachment on a winch around which rope for hoisting and pulling is wound. Cat-line n: a hoisting or pulling line powered by the cat-head and used to lift heavy equipment on the rig. Caving n: collapse of the walls of the wellbore, also called sloughing. Cellar n: a pit in the ground to provide additional height between the rig floor and the wellhead to accommodate the installation of blowout preventers, rat hole, mouse hole, and so forth. It also collects drainage water and other fluids for subsequent disposal. Cement casing v: to fill the annulus between the casing and hole with cement to support the casing and prevent fluid migration between permeable zones. Cement channeling n: an undesirable phenomenon that can occur when casing is being cemented in a borehole. The cement slurry fails to rise uniformly between the casing and borehole wall, leaving spaces void of cement. Ideally, the cement should completely and uniformly surround the casing and form a strong bond to the borehole wall. Cementing n: the application of a liquid slurry of cement and water to various points inside and outside the casing. Chain drive n: a drive system using a chain and chain gears to transmit power. Power transmissions use a roller chain, in which each link is made of side bars, transverse pins, and rollers on the pins. A double roller chain is made of two connected rows of links, a triple roller chain of three, and so forth. Chain tongs n: a tool consisting of a handle and releasable chain used for turning pipe or fittings of a diameter larger than that which a pipe wrench would fit. The chain is looped and tightened around the pipe or fitting, and the handle is used to turn the tool so that the pipe of fitting can be tightened or loosened. PetroServices GmbH Training Center

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Basic Mud Logging Check valve n: a valve that permits flow in one direction only. Choke n: an orifice installed in a line to restrict the flow and control the rate of production. Surface chokes are part of the Christmas tree and contain a choke nipple, or bean, with a small diameter bore that serves to restrict the flow. Chokes are also used to control the rate of flow of the drilling mud out of the hole when the well is closed in with the blowout preventer and a kick is being circulated out of the hole. Choke line n: an extension of pipe from the blowout preventer assembly used to direct well fluids from the annulus to the choke manifold. Choke manifold n: the arrangement of piping and special valves, called chokes, through which drilling mud is circulated when the blowout preventers are closed to control the pressures encountered during a kick. Christmas tree n: the control valves, pressure gauges, and chokes assembled at the top of a well to control the flow of oil and gas after the well has been drilled and completed. Circulate v: to pass from one point throughout a system and back to the starting point. For example, drilling fluid is circulated out of the suction pit, down the drill pipe and drill collars, out the bit, up the annulus, and back to the pits. Circulation n: the movement of drilling fluid out of the mud pits, down the drill string, up the annulus, and back to the mud pits. Combination string n: a casing string that has joints of various collapse resistance, internal yield strength, and tensile strength designed for various depths in a specific well to best withstand the conditions of that well. In deep wells, high tensile strength is required in the top casing joints to carry the load, whereas high collapse resistance and internal yield strength are needed for the bottom joints. In the middle of the casing, average qualities are usually sufficient. The most suitable combination of types and weights of pipe help to ensure efficient production at a minimum cost. Come out of the hole v: to pull the drill string out of the wellbore. This withdrawal is necessary to change the bit, change from a core barrel to the bit, run electric logs, prepare for a drill stem test, run casing, and so on. Company man n: also called company representative. Company representative n: an employee of an operating company whose job is to represent the company’s interest at the drilling location. Complete a well v: to finish work on a well and bring it to productive status. Compound n: a mechanism used to transmit power from the engines to the pump, draw works, and other machinery on a drilling rig. It is composed of clutches, chains and sprockets, belts and pulleys, and a number of shafts, both driven and driving. v: to connect two or more power-producing devices (as engines) to run one piece of driven equipment (as the draw works). Conductor pipe n: a short string of large-diameter casing used to keep the top of the wellbore open and to provide a means of conveying the up-flowing drilling fluid from the wellbore to the mud pit.


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Basic Mud Logging Contract depth n: the depth of the wellbore at which the drilling contract is fulfilled. Core n: a cylindrical sample taken from a formation for geological analysis. Usually a conventional core barrel is substituted for the bit and procures a sample as it penetrates the formation. v: to obtain a formation sample for analysis. Core analysis n: laboratory analysis of a core sample to determine porosity, permeability, lithology, fluid content, angle of dip, geological age, and probable productivity of the formation. Core barrel n: a tubular device from 25 to 60 feet long runs at the bottom of the drill pipe in place of a bit to cut a core sample. Core catcher n: the part of the core barrel that holds the formation sample. Core cutter head n: the cutting element of the core barrel assembly. In design, it corresponds to one of the three main types of bits: drag bits with blades for cutting soft formations; roller bits with rotating cutting for cutting medium formations; and diamond bits for cutting very hard formations. Coupling n: 1. in piping, a metal collar with internal threads used to join two sections of thread pipe. 2. in power transmission, a connection extending longitudinally between a driving shaft and a driven shaft. Most such couplings are flexible and compensate for minor misalignment of the two shafts. Crooked hole n: a wellbore that has deviated from the vertical. It usually occurs in areas where the subsurface formations are difficult to drill, such as a section of alternating hard and soft strata steeply inclined from the horizontal. Crown block n: an assembly of sheaves or pulleys mounted on beams at the top of the derrick over which the drill line is reeved. Cuttings n: the fragments of rock dislodged by the bit and brought to the surface in the drilling mud. Washed and dried samples of the cuttings are analyzed by geologists to obtain information about the formations drilled.

D Daylight tour n: (pronounced “tower”) the shift of duty on a drilling rigs that starts at or about daylight; also called morning tour. Deadline n: the drill line from the crown block sheave to the anchor, so called because it does not move. Deadline tie-down anchor n: a device to which the deadline is attached securely fastened to the mast or derrick substructure. Degasser n: the equipment used to remove unwanted gas from a liquid, especially from a drilling fluid. Density n: the mass or weight of a substance; often expressed in weight per unit volume. For instance, the density of a drilling mud may be 10 pounds per gallon (ppg), 74.8 pounds per cubic foot (lb/ft3), or 1,198.2 kilograms per cubic meter (kg/m3). Specific gravity and API gravity are other units of density.


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Basic Mud Logging Derrick n: a large load-bearing structure, usually of bolted construction. In drilling, the standard derrick has four legs standing at the corners of the substructure and reaching to the crown block. The substructure is an assembly of heavy beams used to elevate the derrick and provide space to install blowout preventers, casing heads, and so forth. Because the standard derrick must be assembled piece by piece, it has largely been replaced by the mast, which can be lowered and raised without disassembly. Derrick man n: the crew member who handles the upper end of the drill string as it is being hoisted out of or lowered into the hole. He is also responsible for the conditioning of the drilling fluid and circulating machinery. Desander n: a centrifugal device for removing sand from drilling fluid to prevent abrasion of the pumps. It may be operated mechanically or by a fast-moving stream of fluid inside a special cone shaped vessel, in which case it is sometimes called a hydrocyclone. Desilter n: a centrifugal device for removing very fine particles, or silt, from drilling fluid to keep the amount of solids in the fluid to the lowest possible point. Usually, the lower the solids content of mud, the faster the rate of penetration. It works on the same principle as a desander. Development well n: 1. a well drilled in proven territory in a field to complete a pattern of production. 2. an exploitation well. Deviation n: the inclination of the wellbore from the vertical. The angle of deviation, angle of drift, or drift angle is the angle in degrees that shows the variation from the vertical as revealed by a deviation survey. Deviation survey n: an operation made to determine the angle from which a bit has deviated from the vertical during drilling. There are two basic deviation survey, or drift survey, instruments: one reveals the angle of deviation only; the other indicates both the angle and direction of deviation. Diamond bit n: a drilling bit that has a steel body surfaced with industrial diamonds. Cutting is performed by the rotation of the very hard diamonds over the rock surface. Diesel-electric power n: the power supplied to a drilling rig by diesel engines driving electric generators, used widely offshore and gaining popularity onshore. Diesel engine n: a high-compression, internal-combustion engine used extensively for powering drilling rigs. In a diesel engine, air is drawn into the cylinders and compressed to very high pressures; ignition occurs as fuel is injected into the compressed and heated air. Combustion takes place within the cylinder above the piston, and expansion of the combustion products imparts power to the piston. Directional drilling n: intentional deviation of a wellbore from the vertical. Although wellbores are normally drilled vertically, it is sometimes necessary or advantageous to drill at an angle from the vertical. Controlled directional drilling makes it possible to reach subsurface areas laterally remote from the point where the bit enters the earth. It involves the use of turbo-drills, Dyna-Drills, whipstocks, or other deflecting tools. Discovery well n: the first oil or gas well drilled in a new field; the well that reveals the presence of a petroleum-bearing reservoir. Subsequent wells are development wells.


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Basic Mud Logging Displacement fluid n: in oil well cementing, the fluid, usually drilling mud or salt water, that is pumped into the well after the cement to force the cement out of the casing and into the annulus. Doghouse n: 1. a small enclosure on the rig floor used as an office for the driller or as a storehouse for small objects. 2. any small building used as an office or for storage. Double n: a length of drill pipe, casing, or tubing consisting of two joints screwed together. Double-board n: the name used for the working platform of the derrick man, or monkey board, when it is located at a height in the derrick or mast equal to two lengths of pipe joined together. Draw works n: the hoisting mechanism on a drilling rig. It is essentially a large winch that spools off or takes in the drill line and thus raises or lowers the drill string and bit. Drill bit n: the cutting or boring element used for drilling. Drill collar n: a heavy, thick-walled tube, usually steel, used between the drill pipe and the bit in the drill string. Drill collars are used to put weight on the bit so that the bit can drill. Driller n: the employee directly in charge of a drilling rig and crew. His main duty is operation of the drilling and hoisting equipment, but he is also responsible for the operation of downhole tools, and pipe measurement. Drilling block n: a lease or a number of leases of adjoining tracts of land that constitute a unit of acreage sufficient to justify the expense of drilling a wildcat. Drilling contractor n: an individual or group of individuals that own a drilling rig or rigs and contract their services for drilling wells to a certain depth. Drilling crew n: a driller, derrick man, and two or more helpers who operate a drilling rig for one tour each day. Drilling fluid n: circulating fluid, one function of which is to force cuttings out of the wellbore and to the surface. While a mixture of clay, water, and other chemical additives is the most common drilling fluid, wells can also be drilled using air, gas, or water as the drilling fluid. Also called circulating fluid. Drilling foreman n: the supervisor of drilling operations on a rig; also the tool pusher or superintendent. Drill line n: a wire rope used to support the drilling tools. Drilling rate n: the speed with which the bit drills the formation; usually called the rate of penetration. Drill pipe n: the heavy seamless tubing used to rotate the bit and circulate the drilling fluid. Joints of pipe 30 feet long are coupled together by means of tool joints. Drill ship n: a ship constructed to permit a well to be drilled from it at an offshore location. While not as stable as other floating structures (as a semi-submersible), drill ships, or ship shapes, are capable of drilling exploratory wells in relatively deep waters. They may have a ship hull, or a catamaran hull.


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Basic Mud Logging Drill string n: all members in the assembly used for drilling by the rotary method from the swivel to the bit, including the kelly, drill pipe and tools joints, drill collars, stabilizers, and various subsequent items. Drill stem test n: a method of gathering data on the potential productivity of a formation before installing casing in a well. Drill string n: the column, or string, of drill pipe with attached tool joints that transmits fluid and rotation power from the kelly to the drill collars and bit. Often, especially in the oil field, term is loosely applied to include both drill pipe and drill collars. Drum n: 1. a cylinder around which wire rope is wound in the draw works. The draw works drum is that part of the hoist upon which the drill line is wound. 2. a steel container of general cylindrical form. Refined products are shipped in steel drums with capacities of about 50 to 55 U.S. gallons (about 200 liters). DST abbr: drill stem test. Dyna-Drill n: a downhole motor driven by drilling fluid that imparts rotary motion to a drilling bit connected to the tool, thus eliminating the need to turn the entire drill string to make hole. The Dyna-Drill, a trade name, is used in straight and directional drilling. Dynamic positioning n: a method by which a floating offshore drilling rig is maintained in position over an offshore well location. Generally, several motors called thrusters are located on the hull(s) of the structure and are actuated by a sensing system. A computer to which the system feeds signals then directs the thrusters to maintain the rig on location.

E Effective permeability n: a measure of the ability of a single fluid to flow through a rock when the pore spaces of the rock are not completely filled or saturated with the fluid. Electric well log n: a record of certain electrical characteristics of formation traversed by the borehole, made to identify the formation, determines the nature and amount of fluids they contain, and estimate their depth. Also called an electric log or electric survey. Electrodynamic brake n: a device mounted on the end of the draw works shaft of a drilling rig. The electrodynamic brake (sometimes called a magnetic brake) serves as an auxiliary to the mechanical brake when pipe is lowered into a well. The braking effect in an electrodynamic brake is achieved by means of the interaction of electric currents with magnets, with other currents, or with themselves. Elevator n: a set of clamps that grips a stand or column of casing, tubing, or drill pipe so that the stand can be raised or lowered into the hole. Evening tour n: (pronounced “tower”) the shift of duty on a drilling rigs that starts in the afternoon and runs through the evening. Exploitation well n: a well drilled to permit more effective extraction of oil from a reservoir. It is sometimes called a development well. Exploration well n: a wildcat well.


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F Fast line n: the end of the drill line that is affixed to the drum or reel of the draw works, so called because it travels with greater velocity than any other portion of the line. Fault n: a break in subsurface strata. Often strata on one side of the fault line have been displaced (upward, downward, or laterally) relative to its original positions. Field n: a geographical area in which a number of oil and gas wells produce from a continuous reservoir. A field may refer to surface area only or to underground productive formations as well. In a single field, there may be several separate reservoirs at varying depths. Fill the hole v: to pump drilling fluid into the wellbore while the pipe is being withdrawn in order to ensure that the wellbore remains full of fluid even though the pipe is withdrawn. Filling the hole lessens the danger of blowout or of caving of the wall of the wellbore. Filter cake n: 1. compacted solid or semisolid material remaining on a filter after pressure filtration of mud with the standard filter press. Thickness of the cake is reported in thirty seconds of an inch or in millimeters. 2. the layer of concentrated solids from the drilling mud that forms on the walls of the borehole opposite permeable formations; also called wall cake or mud cake. Fingerboard n: a rack that supports the tops of the stands of pipe being stacked in the derrick or mast. It has several steel finger-like projections that form a series of slots into which the derrick man can set a stand of drill pipe as it is pulled out of the hole. Fish n: an object left in the wellbore during drilling operations that must be recovered or drilled around before work can proceed. It can be anything from a piece of scrap metal to a part of the drill string. v: 1. to recover from a well any equipment left there during drilling operations, such as a lost bit or drill collar or part of the drill string. 2. to remove from an older well certain pieces of equipment, such as packers, liners, or screen pipe, to allow reconditioning of the well. Fishing tool n: a tool designed to recover equipment lost in the well. Float collar n: a special coupling device, inserted one or two joints above the bottom of the casing string, that contains a check valve to permit fluid to pass downward but not upward through the casing. The float collar prevents drilling mud from entering the casing while it is being lowered, allowing the casing to float during its descent, which decreases the load on the derrick. The float collar also prevents a back flow of cement during the cementing operation. Floor man n: a drilling crew member whose workstation is on the derrick floor. On rotary drilling rigs, there are at least two and usually three or more floor men on each crew. Also called rotary helper and roughneck. Fluid n: a substance that flows and yields to any force tending to change it shape. Liquids and gases are fluids. Formation n: a bed or deposit composed throughout of substantially the same kinds of rock; a lithologic unit. Each different formation is given a name, frequently as a result of the study of the formation outcrop at the surface and sometimes based on fossils found in the formation.


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Basic Mud Logging Formation fracturing n: a method of stimulating production by increasing the permeability of the producing formation. Under extremely high hydraulic pressure, a fluid (as water, oil, alcohol, dilute hydrochloric acid, liquefied petroleum gas, or foam) is pumped downward through tubing or drill pipe and forced into the perforations in the casing. The fluid enters the formation and parts or fractures it. Sand grains, aluminum pellets, glass beads, or similar materials are carried in suspension by the fluid into the fractures. These are called propping agents or proppants. When the pressure is released at the surface, the fracturing fluid returns to the well, and the fractures partially close on the proppants, leaving channels for oil to flow through them to the well. Formation pressure n: the force exerted by fluids in a formation, recorded in the hole at the level of the formation with the well shut in. It is also called reservoir pressure or shut-in bottom-hole pressure. Formation testing n: the gathering of data on a formation to determine its potential productivity before installing casing in a well. The conventional method is the drill stem test. Incorporated in the drill stem testing tool are packers, valves or ports that may be opened and closed from the surface, and a pressure-recording device. The tool is lowered to bottom on a string of drill pipe and the packer set, isolating the formation to be tested from the formations above and supporting the fluid column above the packer. A port on the tool is opened to allow the trapped pressure below the packer to bleed off into the drill pipe, gradually exposing the formation to atmospheric pressure and allowing the well to produce to the surface, where the well fluids may be sampled and inspected. From a record of the pressure readings, a number of facts about the formation may be inferred. Fourable n: a section of drill pipe, casing or tubing consisting of four joints screwed together. Fourable board n: the name used for the working platform of the derrick man, or monkey board, when it is located at a height in the derrick equal to approximately four lengths of pipe joined together. Fracturing n: shortened form of formation fracturing.

G Gas cut mud n: a drilling mud that has entrained formation gas giving the mud a characteristically fluffy texture. When entrained gas is not released before the fluid returns to the well, the weight or density of the fluid column is reduced. Because a large amount of gas in mud lowers its density, gas-cut mud must be treated to lessen the chance of a blowout. Gas sand n: a stratum of sand or porous sandstone from which natural gas is obtained. Gas show n: the gas that appears in drilling fluid returns, indicating the presence of a gas zone. Geologist n: a scientist who gathers and interprets data pertaining to the strata of the earth’s crust. Geology n: the science that relates to the study of the structure, origin, history, and development of the earth and its inhabitants as revealed in the study of rocks, formations, and fossils.


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Basic Mud Logging Graveyard tour n: (pronounced “tower”) the shift of duty on a drilling rigs that starts at or about midnight. Gravity n: the attraction exerted by the earth’s mass on objects at its surface; the weight of a body. Guide shoe n: a short, heavy, cylindrical section of steel filled with concrete and rounded at the bottom, which is placed at the end of the casing string. It prevents the casing from snagging on irregularities in the borehole as it is lowered. A passage through the center of the shoe allows drilling fluid to pass up into the casing while it is being lowered and cement to pass out during cementing operations. Also called casing shoe. Gun-perforate v: to create holes in casing and cement set through a productive formation. A common method of completing a well is to set casing through the oil-bearing formation and cement it. A perforating gun is then lowered into the hole and fired to detonate highpowered jets or shoot steel projectiles (bullets) through the casing and cement and into the pay zone. The formation fluids flow out of the reservoir through the perforations and into the wellbore. Gusher n: an oil well that has come in with such great pressure that the oil jets out of the well like a geyser. In reality, a gusher is a blowout and is extremely wasteful of reservoir fluids and drive energy. In the early days of the oil industry, gushers were common and many times were the only indication that a large reservoir of oil and gas had been struck.

H Hoist n: an arrangement of pulleys and wire rope or chain used for lifting heavy objects; a winch or similar device; the draw works. Hoisting drum n: the large, flanged spooled in the draw works on which the hoisting cable is wound. Hook n: a large hook-shaped device from which the swivel is suspended. It is designed to carry maximum loads ranging from 100 to 650 tons and turns on bearings in its supporting housing. A strong spring within the assembly cushions the weight of a stand (90 feet) of drill pipe, thus permitting the pipe to be made up and broken out with less damage to the tool joint threads. Smaller hooks without the spring are used for handling tubing and sucker rods. Hopper n: a large funnel- or cone-shaped device into which dry components (as powdered clay or cement) can be poured in order to uniformly mix the components with water (or other liquids). The liquid is injected through a nozzle at the bottom of the hopper. The resulting mixture of dry material and liquid may be drilling mud to be used as the circulating fluid in a rotary drilling operation or may be cement slurry used to bond casing to the borehole. Hydraulic fracturing n: an operation in which a specially blended liquid is pumped down a well and into a formation under pressure high enough to cause the formation to crack open. The resulting cracks or fractures serve as passages through which oil can flow into the wellbore. Hydrocarbons n: organic compounds of hydrogen and carbon, whose densities, boiling points, and freezing points increase as their molecular weights increase. Although composed only of two elements, hydrocarbons exist in a variety of compounds, because of


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Basic Mud Logging the strong affinity of the carbon atom for other atoms and for itself. The smallest molecules of hydrocarbons are gaseous; the largest are solids. Petroleum is a mixture of many different hydrocarbons. Hydromatic brake n: a device mounted on the end of the draw works shaft of a drilling rig. The hydromatic brake (often simply called the hydromatic) serves as an auxiliary to the mechanical brake when pipe is lowered into the well. The braking effect in a hydromatic brake is achieved by means of a runner or impeller turning in a housing filled with water.

I Impermeable adj: preventing the passage of fluid. A formation may be porous yet impermeable if there is an absence of connecting passages between the voids within it. Inland barge rig n: a drilling structure consisting of a barge upon which the drilling equipment is constructed. When moved from one location to another, the barge floats, but when stationed on the drill site, the barge is submerged to rest on the bottom. Typically, inland barge rigs are used to drill wells in marshes, shallow inland bays, and in areas where the water covering the drill site is not too deep. Instrumentation n: a device or assembly of devices designed for one or more of the following functions: to measure operating variables (as pressure, temperature, rate of flow, speed of rotation, etc.); to indicate these phenomena with visible or audible signals; to record them, to control them within a predetermined range; and to stop operations if the control fails. Simple instrumentation might consist of an indicating pressure gauge only. In a completely automatic system, the desired range of pressure, temperature, and so on is predetermined and preset. Intermediate casing string n: the string of casing set in a well after the surface casing, but before the production casing, to keep the hole from caving and to seal off troublesome formations. The string is sometimes called protection casing.

J Jackup drilling rig n: an offshore drilling structure with tubular or derrick legs that support the deck and hull. When positioned over the drilling site, the bottoms of the legs rest on the seafloor. A jackup rig is towed or propelled to a location with its legs up. Once the legs are firmly positioned on the bottom, the deck and hull height are adjusted and leveled. Jet bit n: a drilling bit having replaceable nozzles though which the drilling fluid is directed in a high-velocity stream to the bottom of the hole to improve efficiency of the bit. Jet gun n: an assembly, including a carrier and shaped charges that is used in jet perforating. Jet-perforate v: to create a hole through the casing with a shaped charge of high explosives instead of a gun that fires projectiles. The loaded charge is lowered into the hole to the desired depth. Once detonated, the charges emit short, penetrating jets of high-velocity gases that cut holes in the casing and cement and some distance into the formation. Formation fluids then flow into the wellbore through these perforations. Joint n: a single length (about 30 feet) of drill pipe or of drill collar, casing, or tubing that has threaded connections at both ends. Several joints screwed together constitute a stand of pipe. PetroServices GmbH Training Center

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Basic Mud Logging Junk n: metal debris lost in a hole. Junk may be a lost bit, pieces of a bit, milled pieces of pipe, wrenches, or any relatively small object that impedes drilling and must be fished out of the hole. v: to abandon (as a nonproductive well).

K Kelly n: the heavy steel member, four- or six-sided, suspended from the swivel through the rotary table and connected to the topmost joint of drill pipe to turn the drill string as the rotary table turns. It has a bored passageway that permits fluid to be circulated into the drill string and up the annulus, or vice versa. Kelly bushing n: a special device that, when fitted into the master bushing transmits torque to the kelly and simultaneously permits vertical movement of the kelly to make hole. It may be shaped to fit the rotary opening or have pins for transmitting torque. Also called the drive bushing. Kelly spinner n: a pneumatically operated device mounted on top of the kelly that, when actuated, causes the kelly to turn or spin. It is useful when the kelly or a joint of pipe attached to it must be spun up; that is, rotated rapidly in order to make it up. Kick n: an entry of water, gas, oil, or other formation fluid into the wellbore. It occurs because the pressure exerted by the column of drilling fluid is not great enough to overcome the pressure exerted by the fluids in the formation drilled. If prompt action is not taken to control the kick or kill the well, a blowout will occur.

L LACT unit n: an automated system for measuring and transferring oil from a lease gathering system into a pipeline. Latch on v: to attach elevators to a section of pipe to pull it out of or run it into the hole. Lead tongs n: (pronounced “leed”) the pipe tongs suspended in the derrick or mast and operated by a wireline connected to the breakout cat-head. Also called breakout tongs. Lease n: 1. a legal document executed between a land owner, as lessor, and a company or individual, as lessee, that grants the right to exploit the premises for minerals or other products. 2. the area where production wells, stock tanks, separators, and other production equipment are located. Lease automatic custody transfer n: the measurement and transfer of oil from the producer’s tanks to the connected pipeline on an automatic basis without a representative of either having to be present. Location n: the place where a well is drilled. Log n: a systematic recording of data, as from the driller’s log, mud log, electrical well log, or radioactivity log. Many different logs are run in wells being produced or drilled to obtain various characteristics of downhole formations.

M Magnetic brake n: also called an electrodynamic brake. PetroServices GmbH Training Center

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Basic Mud Logging Make a connection v: to attach a joint of drill pipe onto the drill string suspended in the wellbore to permit deepening of the wellbore. Make a trip v: to hoist the drill string out of the wellbore to perform one of a number of operations such as changing bits, taking a core, and so forth, and then to return the drill string to the wellbore. Make hole v: to deepen the hole made by the bit; to drill ahead. Make up v: 1. to assemble and join parts to form a complete unit (as to make up a string of casing). 2. to screw together two threaded pieces. 3. to mix or prepare (as to make up a tank of mud). 4. to compensate for (as to make up for lost time). Make up a joint v: to screw a length of pipe into another length of pipe. Makeup cat-head n: a device attached to the shaft of the draw works that is used as a power source for screwing together joints of pipe; usually located on the driller’s side of the draw works. Mast n: a portable derrick capable of being erected as a unit, as distinguished from a standard derrick that cannot be raised to a working position as a unit. For transporting by land, the mast can be divided into two or more sections to avoid excessive length extending from truck beds on the highway. Master bushing n: a device that fits into the rotary table. It accommodates the slips and drives the kelly bushing so that the rotating motion of the rotary table can be transmitted to the kelly. Also called rotary bushing. Mechanical rig n: a drilling rig in which the source of power is one or more internal combustion engines and in which the power is distributed to rig components through mechanical devices (as chains, sprockets, clutches, and shafts). It is also called a power rig. Mill n: a downhole tool with rough, sharp, extremely hard cutting surfaces for removing metal by grinding or cutting. Mills are run on drill pipe or tubing to grind up debris in the hole, remove stuck portions of drill stem or sections of casing for sidetracking, and ream out tight spots in the casing. They are also called junk mills, reaming mills, and so forth, depending on what use they have. v: to use a mill to cut or grind metal objects that must be removed from a well. Mix mud v: to prepare drilling fluids from a mixture of water or other fluids and one or more of the various dry mud-making materials (as clay, weighting materials, chemicals, etc.). Monkey board n: the derrick man’s working platform. As pipe or tubing is run into or out of the hole, the derrick man must handle the top end of the pipe, which may be as high as 90 feet in the derrick or mast. The monkey board provides a small platform to raise him to the proper height to be able to handle the top of the pipe. Morning tour n: (pronounced “tower”) also called daylight tour. Motorman n: the crew member on a rotary drilling rig responsible for the care and operation of drilling engines. Mouse hole n: an opening through the rig floor, usually lined with pipe, into which a length of drill pipe is placed temporarily for later connection to the drill string.


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Basic Mud Logging Mouse hole connection n: the procedure of adding a length of drill pipe or tubing to the active string in which the length to be added is placed in the mouse hole, made up to the kelly, then pulled out of the mouse hole, and subsequently made up into the string. Mud n: the liquid circulated through the wellbore during rotary drilling operations. In addition to its function of bringing up cuttings to the surface, drilling mud cools and lubricates the bit and drill stem, protects against blowouts by holding back subsurface pressures, and deposits a mud cake on the wall of the borehole to prevent loss of fluids to the formation. Although it originally was a suspension of earth solids (especially clays) in water, the mud used in modern drilling operations is a more complex, three-phase mixture of liquids, reactive solids, and inert solids. The liquid phase may be fresh water, seawater, and may contain one or more conditioners. Mud analysis n: examination and testing of the drilling mud to determine its physical and chemical properties. Mud cake n: the sheath of mud solids that forms on the wall of the hole when the liquid from the mud filters into the formation; also called wall cake or filter cake. Mud circulation n: the act of pumping mud downward to the bit and back up to the surface by normal circulation or reverse circulation. Mud conditioning n: the treatment and control of drilling mud to ensure that it has the correct properties. Conditioning may include the use of additives, the removal of sand or other solids, the removal of gas, the addition of water, and other measures to prepare the mud for conditions encountered in a specific well. Mud engineer n: a person whose duty is to test and maintain the properties of the drilling mud that is specified by the operator. Mud gun n: a pipe that shoots a jet of drilling mud under high pressure into the mud pit to mix additives with the mud. Mud man n: also called a mud engineer. Mud pit n: a series of open tanks usually made of steel plates, through which the drilling mud is cycled to allow sand and sediments to settle out. Additives are mixed with the mud in the pit, and the fluid is temporarily stored there before being pumped back into the well. Modern rotary drilling rigs are generally provided with three or more pits, usually fabricated steel tanks fitted with built-in piping, valves and mud agitators. Mud pits are also called shaker pits, settling pits, and suction pits, depending of their main purpose. Mud pump n: a large, reciprocating pump used to circulate the mud on a drilling rig. A typical mud pump is a single- or double-acting, two- or three-cylinder piston pump whose pistons travel in replaceable liners and are driven by a crankshaft actuated by an engine or motor. Mud-return line n: a trough or pipe placed between the surface connections at the wellbore and the shale shaker, through which drilling mud flows upon its return to the surface from the hole. Mud screen n: also called a shale shaker.


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N Natural gas n: a highly compressible, highly expandable mixture of hydrocarbons having a low specific gravity and occurring naturally in a gaseous form. Besides hydrocarbon gases, natural gas may contain appreciable quantities of nitrogen, helium, carbon dioxide, and contaminants (as hydrogen sulfide and water vapor). Although gaseous at normal temperatures and pressures, certain of the gases comprising the mixture that is natural gas are variable in form and may be found either as gases or as liquids under suitable conditions of temperature and pressure. Needle valve n: a globe valve that incorporates a needle point disk to produce extremely fine regulation of flow. Nipple n: a tubular pipe fitting threaded on both ends and less than 12 inches long. Nipple up v: in drilling, to assemble the blowout-preventer stack on the wellhead at the surface. Normal circulation n: the smooth, uninterrupted circulation of drilling fluid down the drill stem, out the bit, up the annular space between the pipe and the hole, and back to the surface.

O Offshore drilling n: drilling for oil in an ocean, gulf, or sea, usually on the continental shelf. A drilling unit for offshore operations may be a mobile floating vessel with a ship or barge hull, a semi-submersible or submersible base, a self-propelled or towed structure with jacking legs (jackup drilling rig), or a permanent structure used as a production platform when drilling is completed. In general, wildcat wells are drilled from mobile floating vessels (as semi-submersible rigs and drill ships) or from jackups, while development wells are drilled from platforms. Oil field n: the surface area overlying an oil reservoir or reservoirs. Commonly, the term includes not only the surface area, but may include the reservoir, the wells, and production equipment as well. Oil sand n: 1. sandstone that yields oil. 2. (by extension) any reservoir that yields oil, whether or not it is sandstone. Oil zone n: a formation or horizon of a well from which oil may be produced. The oil zone is usually immediately under the gas zone and on top of the water zone if all three fluids are present and segregated. Open adj: 1. of a wellbore, having no casing. 2. of a hole, having no drill pipe or tubing suspended in it. Open hole n: 1. any wellbore in which casing has not been set. 2. open or cased hole in which no drill pipe or tubing is suspended. Operator n: the person or company, either proprietor or lessee, actually operating an oil well or lease. Overshot n: a fishing tool that is attached to tubing or drill pipe and lowered over the outside wall of pipe lost or stuck in the wellbore. A friction device in the overshot, usually either a


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Basic Mud Logging basket or a spiral grapple, firmly grips the pipe, allowing the lost fish to be pulled from the hole.

P P&A abbr: plug and abandon. Pay sand n: the producing formation, often one that is not even sandstone. It is also called pay, pay zone, and producing zone. Perforate v: to pierce the casing wall and cement to provide holes through which formation fluids may enter or to provide holes in the casing so that materials may be introduced into the annulus between the casing and the wall of the borehole. Perforating is accomplished by lowering into the well a perforating gun, or perforator that fires electrically detonated bullets or shaped charges from the surface. Perforating gun n: a device fitted with shaped charges or bullets that is lowered to the desired depth in a well and fired to create penetrating holes in casing, cement and formation. Permeability n: 1. a measure of the ability of fluids to flow through a porous rock. 2. Fluid conductivity of a porous medium. 3. the ability of a fluid to flow within the interconnected pore network of a porous medium. Petroleum n: oil or gas obtained from the rocks of the earth. Pin n: the male section of the tool joint. Pipe rams n: a sealing component for a blowout preventer that closes the annular space between the pipe and the blowout preventer or wellhead. Platform n: an immobile, offshore structure constructed on pilings from which wells are drilled, produced, or both. Plug and abandon v: to place a cement plug into a dry hole and abandon it. Pore n: an opening or space within a rock or mass of rocks, usually small and often filled with some fluid (as water, oil, gas, or all three). Porosity n: the condition of something that contains pores (as a rock formation). Positive choke n: a choke in which the orifice size must be changed to change the rate of flow through the choke. Pressure n: the force that a fluid (liquid or gas) exerts when it is in some way confined within a vessel, pipe, hole in the ground, and so forth, such as that exerted against the inner wall of a tank or that exerted on the bottom of the wellbore by drilling mud. Pressure is often expressed in terms of force per unit of area, as pounds per square inch (psi). Pressure gauge n: an instrument for measuring fluid pressure that usually registers the difference between atmospheric pressure and the pressure of the fluid by indicating the effect of such pressures on a measuring element (as a column of liquid, a weighted piston, a diaphragm, or other pressure-sensitive device).


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Basic Mud Logging Pressure gradient n: a scale of pressure differences in which there is a uniform variation of pressure from point to point. For example, the pressure gradient of a column of water is about 0.433 psi/ft of vertical elevation (9.794 kPa/m). The normal pressure gradient in a well is equivalent to the pressure exerted at any given depth by a column of 10 percent salt water extending from that depth to the surface (i.e., 0.465 psi/ft or 10.518 kPa/m). Pressure relief valve n: a valve that opens at a preset pressure to relieve excessive pressures within a vessel or line; also called a relief valve, safety valve, or pop valve. Preventer n: shortened form of blowout preventer. Primary cementing n: the cementing operation that takes place immediately after the casing has been run into the hole; used to provide a protective sheath around the casing, to segregate the producing formation, and to prevent the migration of undesirable fluids. Prime mover n: an internal-combustion engine that is the source of power for a drilling rig in oil well drilling. Production n: 1. the phase of the petroleum industry that deals with bringing the well fluids to the surface and separating them and with storing, gauging, and otherwise preparing the product for the pipeline. 2. the amount of oil or gas produced in a given period. Proppant n: also called propping agent. Propping agent n: a granular substance (as sand grains, aluminum pellets, or other material) carried in suspension by the fracturing fluid that serves to keep the cracks open when the fracturing fluid is withdrawn after a fracture treatment. Psi abbr: pounds per square inch. Pump n: a device that increases the pressure on a fluid or raises it to a higher level. Various types of pumps include the reciprocating pump, centrifugal pump, rotary pump, jet pump, sucker rod pump, hydraulic pump, mud pump, submersible pump, and bottom hole pump. Pump pressure n: fluid pressure from the action of the pump.

R Radioactivity well logging n: the recording of the natural or induced radioactive characteristics of subsurface formations. A radioactivity log, also known as a radiation log, normally consists of two recorded curves: a gamma ray curve and a neutron curve. Both indicate the types of rock in the formation and the types of fluids contained in the rocks. The two logs may be run simultaneously in conjunction with a collar locator in a cased or uncased hole. Ram n: the closing and sealing component on a blowout preventer. One of three types blind, pipe, or shear - may be installed in several preventers mounted in a stack on top of the wellbore. Blind rams, when closed, form a seal on a hole that has no drill pipe in it; pipe rams, when closed, seal around the pipe; shear rams cut through drill pipe and then form a seal. Ram blowout preventer n: a blowout preventer that uses rams to seal off pressure on a hole that is with or without pipe. It is also called a ram preventer.


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Basic Mud Logging Rat hole n: 1. a hole in the rig floor 30 to 35 feet deep, lined with casing that projects above the floor, into which the kelly and swivel are placed when hoisting operations are in progress. 2. a hole of a diameter smaller than the main hole that is drilled in the bottom of the main hole. v: to reduce the size of the wellbore and drill ahead. Reeve v: to pass (as the end of a rope) through a hole or opening in a block or similar device. Reeve the line v: to string wire rope drill line through the sheaves of the traveling and crown blocks to the hoisting drum. Relative permeability n: a measure of the ability of two or more fluids (as water, gas, and oil) to flow through a rock formation when the formation is totally filled with several fluids. The permeability measure of a rock filled with two or more fluids is different from the permeability measure of the same rock filled with only one fluid. Reserve pit n: 1. (obsolete) a mud pit in which a supply of drilling fluid was stored. 2. a waste pit, usually excavated, earthen-walled pit. It may be lined with plastic to prevent contamination of the soil. Reservoir n: a subsurface, porous, permeable rock body in which oil and/or gas is stored. Most reservoir rocks are limestone, dolomite, sandstone, or a combination of these. The three basic types of hydrocarbon reservoirs are oil, gas, and condensate. An oil reservoir generally contains three fluids - gas, oil, and water - with oil the dominant product. In the typical reservoir, these fluids occur in different phases because of the variance in their gravities. Gas, the lightest, occupies the upper part of the reservoir rocks; water, the lower part; and oil, the intermediate section. In addition to occurring as a cap or in solution, gas may accumulate independently of the oil; if so, the reservoir is called a gas reservoir. Associated with the gas, in most instances, are salt water and some oil. In a condensate reservoir, the hydrocarbons may exist as a gas, but when brought to the surface, some of the heavier ones condense to a liquid or condensate. Reservoir pressure n: the pressure in a reservoir under normal conditions. Reverse circulation n: the return of drilling fluid through the drill stem. The normal course of drilling fluid circulation is downward through the drill stem and upward through the annular space surrounding the drill stem. For special problems, normal circulation is sometimes reversed, and the fluid returns to the surface through the drill stem, or tubing, after being pumped down the annulus. Rig n: the derrick or mast, draw works, and attendant surface equipment of a drilling unit. Rig down v: to dismantle the drilling rig and auxiliary equipment following the completion of drilling operations; also called tear down. Rig up v: to prepare the drilling rig for making hole; to install tools and machinery before drilling is started. Roller cone bit n: a drilling bit made of two, three, or four cones, or cutters, that are mounted on extremely rugged bearings. Also called rock bits. The surface of each cone is made up of rows of steel teeth or rows of tungsten carbide inserts. Rotary bushing n: also called master bushing.


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Basic Mud Logging Rotary drilling n: a drilling method in which a hole is drilled by a rotating bit to which downward force is applied. The bit is fastened to and rotated by the drill stem, which also provides a passageway through which the drilling fluid is circulated. Additional joints of drill pipe are added as drilling progresses. Rotary helper n: a worker on a drilling rig, subordinate to the driller, sometimes called a roughneck, floorman, or rig crew member. Rotary hose n: a reinforced, flexible tube on a rotary drilling rig that conducts the drilling fluid from the mud pump and standpipe to the swivel and kelly; also called the mud hose or kelly hose. Rotary table n: the principal component of a rotary or rotary machine, used to turn the drill stem and support the drilling assembly. It has a beveled gear arrangement to create the rotational motion and an opening into which bushings are fitted to drive and support the drilling assembly. Roughneck n: also called a rotary helper. Round trip n: the action of pulling out and subsequently running back into the hole a string of drill pipe or tubing. It is also called tripping. Roustabout n: 1. a worker on an offshore rig who handles the equipment and supplies that are sent to the rig from the shore base. The head roustabout is very often the crane operator. 2. a worker who assists the foreman in the general work around a producing oil well, usually on the property of the oil company. 3. a helper on a well-servicing unit. Run in v: to go into the hole with tubing or drill pipe.

S Samples n pl: 1. the well cuttings obtained at designated footage intervals during drilling. From an examination of these cuttings, the geologist determines the type of rock and formation being drilled and estimates oil and gas content. 2. small quantities of well fluids obtained for analysis. Sand n: 1. an abrasive material composed of small quartz grains formed from the disintegration of preexisting rocks. Sand consists of particles less than 2 millimeters and greater than 1/16 of a millimeter in diameter. 2. sandstone. Scratcher n: a device fastened to the outside of casing that removes the mud cake from the wall of the hole to condition the hole for cementing. By rotating or moving the casing string up and down as it is being run into the hole, the scratcher, formed of stiff wire, removes the cake so that the cement can bond solidly to the formation. Secondary cementing n: any cementing operation after the primary cementing operation. Secondary cementing includes a plug-back job, in which a plug of cement is positioned at a specific point in the well and allowed to set. Wells are plugged to shut off bottom water or to reduce the depth of the well for other reasons. Seismograph n: a device that detects reflections of vibrations in the earth, used in prospecting for probable oil-bearing structures. Vibrations are created by discharging explosives in shallow boreholes, by striking the surface with a heavy blow, or by generating


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Basic Mud Logging low-frequency sound waves. The type and velocity of the vibrations as recorded by the seismograph indicate the general characteristics of the section of earth through which the vibration pass. Semi-submersible drilling rig n: a floating, offshore drilling structure that has hulls submerged in the water but not resting on the seafloor. Living quarters, storage space, and so forth are assembled on the deck. Semi-submersible rigs are either self-propelled or towed to a drilling site and either anchored or dynamically positioned over the site or both. Semi-submersibles are more stable than drill ships and are used extensively to drill wildcat wells in rough water such as the North Sea. Set casing v: to run and cement casing at a certain depth in the wellbore. Sometimes, the term “set pipe” is used when referring to setting casing. Settling pit n: the mud pit into which mud flows and in which heavy solids are allowed to settle out. Often auxiliary equipment (as de-sanders) must be installed to speed up this process. Shaker n: shortened form of shale shaker. Shaker pit n: the mud pit adjacent to the shale shaker, usually the first pit into which the mud flows after returning from the hole. Shale n: a fine-grained sedimentary rock composed of consolidated silt and clay or mud. Shale is the most frequently occurring sedimentary rock. Shale shaker n: a series of trays with sieves that vibrate to remove cuttings from the circulating fluid in rotary drilling operations. The size of the openings in the sieve is carefully selected to match the size of the solids in the drilling fluid and the anticipated size of the cuttings. Also called a shaker. Shaped charge n: a relatively small container of high explosive that is loaded into a perforating gun. Upon detonation, the charge releases a small, high-velocity stream of particles (a jet) that penetrates the casing, cement, and formation. Shear rams n: the components in a blowout preventer that cut, or shears, through drill pipe and form a seal against well pressure. Shear rams are used in mobile offshore drilling operations to provide a quick method of moving the rig away from the hole when there is no time to trip the drill stem of the hole. Sheave n: (pronounced “shiv”) a grooved pulley. Show n: the appearance of oil or gas in cuttings, samples, cores, and so forth of drilling mud. Shut down v: to stop work temporarily or to stop a machine or operation. Shut-in bottom hole pressure n: the pressure at the bottom of a well when the surface valves on the well are completely closed. The pressure caused by fluids that exist in the formation at the bottom of the well. Sidetrack v: to drill around broken drill pipe or casing that has become lodged permanently in the hole, using a whipstock, turbo-drill, or other mud motor.


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Basic Mud Logging Sidewall coring n: a coring technique in which core samples are obtained from a zone that has already been drilled. A hollow bullet is fired into the formation wall to capture the core and then retrieved on a flexible steel cable. Core samples of this type usually range from 3/4 to 1 3/16 inches in diameter and from 3/4 to 1 inch in length. This method is especially useful in soft rock areas. Single n: a joint of drill pipe. Slips n pl: wedge-shaped pieces of metal with teeth or other gripping elements that are used to prevent pipe from slipping down into the hole or to hold pipe in place. Rotary slips fit around the drill pipe and wedge against the master bushing to support the pipe. Power slips are pneumatically or hydraulically actuated devices that allow the crew to dispense with the manual handling of slips when making a connection. Slurry n: a plastic mixture of cement and water that is pumped into a well to harden; there it supports the casing and provides a seal in the wellbore to prevent migration of underground fluids. Sonic logging n: the recording of the time required for a sound wave to travel a specific distance through a formation. Difference in observed travel times is largely caused by variations in porosities of the medium, an important determination. The sonic log, which may be run simultaneously with a spontaneous potential log or a gamma ray log, is useful for correlation and often is used in conjunction with other logging services for substantiation of porosities. It is run in an uncased hole. Spear n: a fishing tool used to retrieve pipe lost in a well. The spear is lowered down the hole and into the lost pipe, and when weight, torque, or both are applied to the string to which the spear is attached, the slips in the spear expand and tightly grip the inside of the wall of the lost pipe. Then the string, spear, and lost pipe are pulled to the surface. Specific gravity n: the ratio of the weight of a given volume of a substance at a given temperature to the weight of an equal volume of a standard substance at the same temperature. For example, if 1 cubic inch of water at 39oF weighs 1 unit and 1 cubic inch of another solid or liquid at 39oF weighs 0.95 units, then the specific gravity of the substance is 0.95. In determining the specific gravity of gases, the comparison is made with the standard of air or hydrogen. Spinning cat-head n: a spooling attachment on the makeup cat-head to permit use of a spinning chain to spin up or make up drill pipe. Spinning chain n: a Y-shaped chain used to spin up (tighten) one joint of drill pipe to another. In use, one end of the chain is attached to the tongs, another end to the spinning cat-head, and the third end is free. The free end is wrapped around the tool joint, and the cat-head pulls the chain off the causing joint, to spin (turn) rapidly and tighten up. After the chain is pulled off the joint, the tongs are secured in the same spot, and continued pull on the chain (and thus on the tongs) by the cat-head makes up the joint to final tightness. Spud v: to move the drill stem up and down in the hole over a short distance without rotation. Careless execution of this operation creates pressure surges that can cause a formation to break down, which results in lost circulation. Spud in v: to being drilling, to start the hole.


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Basic Mud Logging Squeeze cementing n: the forcing of cement slurry by pressure to specified points in a well to cause seals at the points of squeeze. It is a secondary cementing method that is used to isolate a producing formation, seal off water, repair casing leaks, and so forth. Stab v: to guide the end of a pipe into a coupling or tool joint when making a connection. Stabbing board n: a temporary platform erected in the derrick or mast some 20 to 40 feet above the derrick floor. The derrick man or another crew member works on the board while casing is being run in a well. The board may be wooden or fabricated of steel girders floored with anti-skid material and powered electrically to raise or lower it to the desired level. A stabbing board serves the same purpose as a monkey board but is temporary instead of permanent. Stake a well v: to locate precisely on the surface of the ground the point at which a well is to be drilled. After exploration techniques have revealed the possibility of the existence of a subsurface hydrocarbon-bearing formation, a certified and registered land surveyor drives a stake into the ground to mark the spot where the well is to be drilled. Stand n: the connected joints of pipe racked in the derrick or mast when making a trip. On a rig, the usual stand is 90 feet long (three lengths of pipe screwed together) or a treble. Standpipe n: a vertical pipe rising along the side of the derrick or mast, which joins the discharge line leading from the mud pump to the rotary hose and through which mud is pumped going into the hole. Stimulation n: any process undertaken to enlarge old channels or create new ones in the producing formation of a well (e.g., acidizing or formation fracturing). Stratification n: the natural layering or lamination characteristic of sediments and sedimentary rocks. Stratigraphic trap n: a petroleum trap that occurs when the top of the reservoir bed is terminated by other beds or by a change of porosity or permeability within the reservoir itself. String n: the entire length of casing, tubing, or drill pipe run into a hole; the casing string. String up v: to thread the drill line through the sheaves of the crown block and traveling block. One end of the line is secured to the hoisting drum and the other to the derrick substructure. Structural trap n: a petroleum trap that is formed because of deformation (as folding or faulting) of the rock layer that contains petroleum. Compare stratigraphic trap. Stuck pipe n: drill pipe, drill collars, casing, or tubing that has inadvertently become immobile in the hole. It may occur when drilling is in progress, when casing is being run in the hole, or when the drill pipe is being hoisted. Sub n: a short, threaded piece of pipe used to adapt parts of drill string that cannot otherwise be screwed together because of differences in thread size or design. A sub may also perform a special function. Lifting subs are used with drill collars to provide a shoulder to fit the drill pipe elevators. A kelly saver sub is placed between the drill pipe and kelly to prevent excessive thread wear of the kelly and drill pipe threads. A bent sub is used when drilling a directional hole. Sub is a sort expression for substitute. PetroServices GmbH Training Center

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Basic Mud Logging Submersible drilling rig n: an offshore drilling structure with several compartments that are flooded to cause the structure to submerge and rest on the seafloor. Most submersible rigs are used only in shallow water. Substructure n: the foundation on which the derrick or mast and usually the draw works sit; contains space for storage and well control equipment. Suction pit n: the mud pit from which mud is picked up by the suction of the mud pumps; also called a sump pit and mud suction pit. Surface casing n: also called surface pipe. Surface data logging n: the recording of information derived from examination and analysis of formation cuttings made by the bit and mud circulated out of the hole. A portion of the mud is diverted through a gas-detecting device. Cuttings brought up by the mud are examined under ultraviolet light to detect the presence of oil and gas. Surface data logging is often carried out in a portable laboratory set up at the well. Surface pipe n: the first string of casing (after the conductor pipe) that is set in a well, varying in length from a few hundred to several thousand feet. Some states require a minimum length to protect freshwater sands. Swivel n: a rotary tool that is hung from the rotary hook and traveling block to suspend and permit free rotation of the drill stem. It also provides connections for the rotary hose and passageway for the flow of drilling fluid into the drill stem. Syncline n: a down-warped, trough-shaped configuration of folded, stratified rocks.

T TD abbr: total depth. Thread protector n: a device that is screwed onto or into pipe threads to protect the threads from damage when the pipe is not in use. Protectors may be metal or plastic. Thribble n: a stand of pipe made up of three joints and handled as a unit. Thribble board n: the name used for the working platform of the derrick man, or monkey board, when it is located at a height in the derrick equal to three lengths of pipe joined together. Throw the chain n: to flip the spinning chain up from a tool joint box so that the chain wraps around the tool joint pin after it is stabbed into the box. The stand or joint of drill pipe is turned or spun by a pull on the spinning chain from the cat-head or draw works. Tight formation n: a petroleum- or water-bearing formation of relatively low porosity and permeability. Tight hole n: a well about which information is restricted and passed only to those authorized for security or competitive reasons. Tongs n pl: the large wrenches used for turning when making up or breaking out drill pipe, casing, tubing, or other pipe; variously called casing tongs and rotary tongs according to the


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Basic Mud Logging specific use. Power tongs are pneumatically or hydraulically operated tools that serve to spin the pipe up tight and, in some instances, to apply the final makeup torque. Tool joint n: a heavy coupling element for drill pipe made of special alloy steel. Tool joints have coarse, tapered threads and seating shoulders designed to sustain the weight of the drill stem, withstand the strain of frequent coupling and uncoupling, and provide a leak proof seal. The male section of the joint, or the pin, is attached to one end of a length of drill pipe, and the female section, or box, is attached to the other end. The tool joint may be welded to the end of the pipe or screwed on or both. A hard metal facing is often applied in a band around the outside of the tool joint to enable it to resist abrasion from the walls of the borehole. Tool pusher n: an employee of a drilling contractor who is in charge of the entire drilling crew and the drilling rig. Also called a drilling rig foreman, manager, supervisor, or rig superintendent. Torque n: the turning force that is applied to a shaft or other rotary mechanism to cause it to rotate or tend to do so. Torque is measured in foot-pounds, joules, meter-kilograms, and so forth. Torque converter n: a connecting device between a prime mover and the machine actuated by it. The elements that pump the fluid in the torque converter automatically increase the output torque of the engine to which the torque is applied, with an increase of load on the output shaft. Torque converters are used extensively on mechanical rigs that have a compound. Total depth n: the maximum depth reached in a well. Tour n: (pronounced “tower”) an 8- or 12-hour shift worked by a drilling crew or other oil field workers. The most common divisions of tours are daylight, evening, and graveyard, if 8-hour tours are employed. Transmission n: the gear or chain arrangement by which power is transmitted from the prime mover to the draw works, mud pump, or rotary table of a drilling rig. Trap n: layers of buried rock strata that are arranged so that petroleum accumulates in them. Traveling block n: an arrangement of pulleys, or sheaves, through which drilling cable is reeved and that moves up and down in the derrick or mast. Tricone bit n: a type of bit in which three cone-shaped, cutting devices are mounted in such a way that they inter-mesh and rotate together as the bit drills. The bit body may be fitted with nozzles, or jets, through which the drilling fluid is discharged. A one-eyed bit is used in soft formations to drill a deviated hole. Trip n: the operation of hoisting the drill stem from and returning it to the wellbore. Turbo-drill n: a drilling tool that rotates a bit attached to it by the action of the drilling mud on the turbine blades built into the tool. When a turbo-drill is used, rotary motion is imparted only at the bit; therefore, it is unnecessary to rotate the drill stem. Although straight holes can be drilled with the tool, it is used most often in directional drilling.


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U Unit operator n: the oil company in charge of development and producing in an oil field in which several companies have joined together to produce the field.

V Valve n: a device used to control the rate of flow in a line, to open or shut off a line completely, or to serve as an automatic or semiautomatic safety device. Those with extensive usage include the gate valve, plug valve, globe valve, needle valve, check valve, and pressure relief valve. V-belt n: a belt with a trapezoidal cross-section that is made to run in sheaves or pulleys, with grooves of corresponding shape. Vug n: a cavity in a rock.

W Waiting on cement adj: pertaining to or during the time when drilling or completion operations are suspended so the cement in a well can harden sufficiently. Wall cake n: also called filter cake and mud cake. Weevil n: shortened form of boll weevil. Weight indicator n: an instrument near the driller’s position on a drilling rig. It shows both the weight of the drill stem that is hanging from the hook (hook load) and the weight that is placed on the bit by the drill collars (weight on bit). Weighting material n: a material that has high specific gravity and is used to increase the density of drilling fluids or cement slurries. Wellbore n: a borehole; the hole drilled by the bit. A wellbore may have casing in it or may be open (i.e., uncased), or a portion of it may be cased and a portion of it may be open. Also called borehole or hole. Well completion n: the activities and methods necessary to prepare a well for the production of oil and gas; the method by which a flow line for hydrocarbons is established between the reservoir and the surface. The method of well completion used by the operator depends on the individual characteristics of the producing formation or formations. These techniques include open-hole completions, sand exclusion completions, tubingless completions, multiple completions, and miniaturized completions. Wellhead n: the equipment installed at the surface of the wellbore. A wellhead includes such equipment as the casing head and tubing head. adj pertaining to the wellhead (as wellhead pressure). Well logging n: the recording of information about subsurface geologic formations. Logging methods include records kept by the driller, mud and cutting analyses, core analysis, drill stem tests, and electric and radioactivity procedures. Well stimulation n: any of several operations used to increase the production of a well.


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Basic Mud Logging Whipstock n: a long, steel casing that uses an inclined plane to cause the bit to deflect from the original borehole at a slight angle. Whipstocks are sometimes used in controlled directional drilling, to straighten crooked boreholes, and to sidetrack to avoid unretrieved fish. Wildcat n: 1. a well drilled in an area where no oil or gas production exists. With present-day exploration methods and equipment, about one wildcat out of every nine proves to be productive although not necessary profitable. 2. (nautical) a geared sheave of a windlass used to pull anchor chain. v: to drill wildcat wells. Wireline n: a slender, rod like or threadlike piece of metal, usually small in diameter, this is used for lowering special tools (such as logging sondes, perforating guns, and so forth) into the well. Wire rope n: a cable composed of steel wires twisted around a central core of hemp or other fiber to create a rope of great strength and considerable flexibly. Wire rope is used as drill line (in rotary and cable-tool rigs), coring line, servicing line, winch line, and so on.


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Appendix A

Hole capacity table


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Appendix A

Hole capacity table


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Appendix A

Hole capacity table


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Appendix B

Casing data


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Appendix B

Casing data


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Appendix B

Casing data


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Appendix B

Casing data


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Appendix B

Casing data


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Appendix B

Casing data


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Appendix B

Casing data


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Appendix B

Casing data


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Appendix B

Casing data


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Appendix B

Casing data


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Appendix B

Casing data


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Appendix B

Casing data


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Appendix B

Casing data


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Appendix B

Casing data


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Appendix B

Casing data


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Appendix B

Casing data


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Appendix B

Casing data


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Appendix C

Drill collar data


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Appendix C

Drill collar data


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Appendix C

Drill collar data


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Appendix C

Drill collar data


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Appendix C

Drill collar data


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Appendix C

Drill collar data


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Appendix C

Drill collar data


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Appendix C

Drill collar data


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Appendix D

Drill pipe data and tool joint data


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Appendix D



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Appendix D



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Appendix D



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Appendix D



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Appendix E

Buoyancy factors


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