SUMMER INTERNSHIP REPORT
PANDIT DEENDAYAL PETROLEUM UNIVERSITY
Submitted to: Dr. R. K. Bawa General Manager (Chemistry) ONGC, Jodhpur
Dr. Sharad Kr. Shankar Dy. General Manager (Chemistry) ONGC, Jodhpur
Submitted by : Prakhar Mathur B. Tech. 2 year (Petroleum Technology) School of Petroleum Technology Pandit Deendayal Petroleum University, Gandhinagar nd
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ACKNOWLEDGEMENT Apart from the efforts of me, the success of this project depends largely on the encouragement and guidelines of many others. I take this opportunity to express my gratitude to the people who have been instrumental in the successful completion of this project. I would like to show my greatest appreciation to Dr Sharad Sharad Kr. Shankar and Dr. R. K. Bawa. I can’t say thank you enough for tremendous support and help. I feel motivated and encouraged every time I attend their meeting. Without their encouragement and guidance this project would not have materialized. The guidance and support received from all the team members such as , Mr. Vikram Saxena , Mr. Atul Kumar and Mr. Baireddy Aneel, was vital for the success of the project. I am grateful for their constant support and help.
My thanks and appreciation also goes to my colleague in developing the project and people who have hav e willingly helped me out with their abilities.
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CONTENTS
CONTENTS
PAGE NO.
INTRODUCTION OF ONGC
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WELL PLANNING
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OVERVIEW OF PLANNING PROCESS
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GTO
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CASING
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WELLHEAD SELECTION
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BOP REQUIREMENT
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CEMENTING PROGRAMME
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MUD PROGRAMME
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BIT AND HYDRAULICS PROGRAMME 26 EVALUATION REQUIREMENTS
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WELL COST ESTIMATION
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REFERENCES
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INTRODUCTION OF ONGC ONGC - WORLD’D NO. 1 E & P COMPANY ONGC has achieved the distinction of Numero Uno ranking in the pure E & P th category, not only in Asia, but on the global scale. ONGC has been ranked 18 in the overall listing of global energy companies as per plats “top 250 Global Energy Company Ranking 2010”. PERFORMANCE : 2009-10 Highest reserve accretion in last two decades ONGC accreted 82.98 Million Tonnes of Oil Equivalent (MTOE) of Ultimate Reserves (3P) in domestic operated fields-the highest in last two decades. Total reserve accretion in domestic basins has been 87.37 MTOE (including 4.39 MTOE from ONGC share in joint ventures (JVs)). Initial in place reserve accretion in domestic basins was 273.42 MTOE including 22.82 MTOE from ONGC share in JVs. Reserve Replacement Ratio (RRR) Reserve Replacement Ratio i.e. the ratio of reserve accretion to the production of ONGC in its domestic oil fields in this fiscal has been quite impressive at th 1.74 for 3P reserves; again the highest in last two decades. This is 5 consecutive ONGC maintain RRR of more than 1 against global feature of lower than 1 registered by large number of o f oil companies. Oil & gas Production levels maintained ONGC has maintained oil and gas production levels despite global trend of declining production from matured oil fields. During FY’10, the combine oil and gas production of ONGC’s share in PSC-JVs, was 60.93 MTOE; marginally lower as compared to 61.23 MTOE in FY’09. Production from overseas fields registered 8.87 MTOE; the highest ever. Largest oil and gas producer in the country
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Oil and gas production from domestic fields, including ONGC’s share in PSC JVs has been 52.06 MTOE during FY’10 against 52.45 MTOE during FY’09. ONGC accounted for 79% of India’s crude oil and 54% of natural gas production during FY’10.
Highest-ever production from overseas assets ONGC Videsh Limited (OVL) , the flagship wholly owned subsidiary for overseas operations has now footprints across 15 countries with 39 projects Since its first hydrocarbon revenue from overseas in 2002—03 from Vietnam, this year OVL registered highest-ever production of 8.87 MTOE of oil and gas. ONGC bags highest number of blocks in NELP-VIII In NELP-VIII bid round, ONGC in partnership with its consortia members, submitted the bids for 25 exploration blocks and won 17 of these. In the eight NELP round which have been rolled out so far, ONGC has won 50% of the blocks i.e. 121 out of 242blocks awarded by Govt. of o f India. ONGC now hold 80 NELP blocks (70 as operator)and 62 nomination n omination blocks. Alternate sources of energy %! MW Wind power farms set up near Bhuj in Gujrat with an investment of rs3,080 million in September, 2009 is already is already operational. The electricity generated is wheeled through Gujarat state electricity grid for captive consumption by ONGC at Ankleshar, Ahmedabad, Mehsana and vadodara ONGC plans to setting up 102MW wind farm in Rajasthan. ONGC Energy Centre set up for holistic research for new and alternate energy sources has been pursuing a number of new projects like-thermo-chemical generation of hydrogen, bioconversion of coal/ oil to methane gas, Uranium exploration, Solid state lighting and Solar PV Energy Farm. Corporate Social Responsibility (CSR) ONGC has earmarked 2% of net profit fir various CSR projects. A dedicated group at the corporate level with regional support oversees the CSR project implementation. Some of the major schemes in the policy includes; •
Education including vocational courses. 6
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Health care
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Entrepreneurship (self help and lively hood generation) schemes.
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Infrastructure support near our operational areas.
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Environment protection, Ecological conservation, promotion.
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Women’s empowerment, girl child development, gender sensitive projects.
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Water management including ground water recharge.
Global rankings •
No. 1 E & P company in the world among leading global energy majors as per plats 2010.
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No. 24 in PFC ENERGY 50 Ranked 24 among the global publicitylisted energy companies as per “PFC Energy50” list (January, 2010).
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Finance Asia ranks ONGC no. 1 among Indian blue chips. Ranked number 1 Top Blue Chip of the India in the Finance Asia 100 list for 2009 with the highest aggregate net profit(before exceptional) over the period 2006-2008.
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ONGC ranked at 155 position in Forbes Global 2000 list for 2010.
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National rankings •
ONGC ranked at second position in FE500 F E500 list 2010.
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Business today Ranks ONGC as best company to work for in core sector.
AWARDS OISD Awards
ONGC and MRPL have won the following six ‘Oil Industry Safety Awards’ for the year 2008-2009, instituted by Oil Industry Safety Directorate (DISD), MoP&NG. Cauvery Asset has been declared as winner in the category Oil & Gas Assets (Onshore) on safety standards.
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Heera Processing plant has been adjudged as the best offshore production Platform under PSUs category on safety standards.
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Sagar Shakti has been adjudged as the best offshore drilling rig, under PSU category on safety standards.
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MRPL has been ranked number nu mber two in Refineries category.
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MRPL has also been rated as the most safe refinery in last three years.
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ONGC’s Rajahmundry Asset has been rated as the most safe Onshore Oil & Gas Asset in last three years.
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ONGCian Shri Supriyo Chowdhury, Chief Engineer (Drilling), Assam Asset has been selected for a cash award for his valuable contribution in the area of safety.
Dainik Bhaskar India Pride Awards for Excellence
ONGC bagged the coveted Gold Award in the CSR category of thr “Dainik Bhaskar India Pride Awards for Excellence in PSUs” instituted by Dainik Bhaskar Group (October, 2010).
ONGC bags Best Overall Performance Award for oil and gas conservation programmes
ONGC bagged the Best Overall Performance Award instituted by Petroleum Conservation Research Association (PCRA) amongst the upstream sector Oil companies for the oil nad gas conservation programmes during the year 2009 (January, 2010).
ONGC bags 5 Development
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BML Munjal Award for excellence in Learning & th
ONGC clinched 5 BML Munjal Award for excellence in Learning & Development in Public sector category, instituted in the name of Dr. Brijmohan Lall Munjal (BML), Chairman, Hero Group (March, 2010).
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DSIG Award to ONGC
ONGC clinched two DSIG-PSU awards 2010, one for excellent overall Performance in category of Heavy Weights and the other for Highest Market Capitalisation amongst PSU’s in the category of Wealth Builders (April, 2010).
ONGC gets Amity Leadership for Business Excellence for leveraging IT
ONGC has been awarded Amity Leadership for Business Excellence for leveraging IT in Oil & Gas Industry instituted by the Amity University (January, 2010).
Golden Peacock award for corporate Governance
ONGC has been conferred with Golden Peacock Award for Excellence in Corporate Governance for 2009 instituted by the World Council of Corporate Governance, London (October, 2009)
Hazira Plant bags commendation at CII-ITC Sustainability Awards 2009
ONGC, Hazira Plant received “Commendation for Strong Commitment” among independent units for the year 2009 at the CII-ITC Sustainability Awards (November, 2009).
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ONGC in Rajasthan The forward base office of ONGC is located at Jodhpur. In Rajasthan ONGC is exploring gas from Thar Desert of Jaisalmer. The Jaisalmer Basin, Western Rajasthan is located at the eastern flank of Indus Basin. Presence of huge volume of sediments with adequate good source reservoir rock combination marks this basin prospective for hydrocarbon exploration. A number of significant oil and gas fields have been discovered in the Indus basin across our frontiers. However, such discoveries are relatively few in numbers do not commensurately match with the vast prospective basinal area for exploration. Accordingly, ONGC limited exploration for hydrocarbons in Rajasthan since its inception in 1956. However, exploratory inputs had been rather limited due to various logistic problems and also due to the lack of major discovery in this basin except two gas fields at Manhera Tibba and Ghotaru. Nevertheless interception of recent seismic data acquired through in house and outside agencies have resulted in identification of a number of structural prospects. No discovery has been made since 1983. Till end of 1989 indication of oil have been found in few wells but commercial oil strike has remained elusive. A gas collection station (GCS) has been established in Gamnewala (around 100 k.m. away from Jaisalmer) and the gas collected here is supplied to RVVNL (Rajasthan Vidyut Vitaran Nigam Limited) Ramgarh for running turbine to produce electricity. Since the year 2002 ONGC has struck gas at Cinnewala field which is good in terms of quality and quantity of hydrocarbons and may hopefully usher in a new era for ONGC in Rajasthan.
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WELL PLANNING Well planning is perhaps the most demanding aspect of drilling engineering. It requires the integration of engineering principles, corporate or personal philosophies, and experience factors. Although well planning methods and practices may vary within the drilling industry, the end result should be a safely drilled, minimum-cost hole that satisfies the reservoir engineer's requirements for oil and gas production. Well Planning is defined as those, primarily p rimarily engineering activities, which follow on from the identification of a subsurface target for a well (exploration, appraisal, or development well) until the completion of that well. This includes: •
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Definition of well objectives Planning of the well trajectory Selection of drilling hardware (bits, tubulars, mud, etc.) Planning of casing points Logging objectives and selection of logging tools (MWD, LWD, wireline logs) Test program and decision criteria for testing Completion program and criteria for completion
Well Planning in context of platform planning (i.e., planning a group of wells from a platform or pad at one time to allow engineering and economic optimization of the entire platform). This ties to entire field development planning (for a given set of targets in a new field, optimize the number and locations of platforms) Well Planning Objective
The objective of well planning is to formulate a program from many variables for drilling a well that has the following characteristics: • Safety • Minimum cost • Usable Unfortunately, it is not always possible to accomplish these objectives on each well due to constraints based on items such as geology and drilling equipment, i.e., temperature, casing limitations, hole sizing, or budget. 11
WELL PLANNING 12
Safety: Safety should be the highest priority in well planning. Personnel considerations must be placed above all other aspects of the plan. In some cases, the plan must be altered during the course of drilling the well when unforeseen drilling problems endanger the crew. Failure to stress crew safety has resulted in loss of life and burned or permanently pe rmanently crippled individuals.
The second priority involves the safety of the well. The well plan must be designed to minimize the risk of blowouts and other factors that could create problems. This design requirement must be adhered to vigorously in all aspects of the plan. Minimum Cost. A valid objective of the well planning process is to minimize the cost of the well without jeopardizing the safety aspects. In most cases, costs can be reduced to a certain level as additional effort is given to the planning (Fig. 1-1). 1 -1). It is not noble to build "steel monuments" in the name of safety if the additional expense is not required. On the other hand, monies should be spent as necessary to develop d evelop a safe system. Usable Holes. Drilling a hole to the target depth is not completely satisfactory if the final well configuration is not usable. In this case, the term “usable” implies the following •
The hole diameter is sufficiently large so an adequate adequ ate completion can
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The hole or producing formation fo rmation is not irreparably damaged.
Fig.1. Well costs can be reduced dramatically if proper well planning is implemented 13
Classification of Well Types The drilling engineer is required to plan a variety of well types, including the following:
Well Type
Characteristics
Wildcat
Not known (or little) geological foundation for site selection.
Exploratory
Site based on seismic data, satellite surveys, etc.; no known drilling data in the prospective horizon.
Step-out
Delineates the reservoir's boundaries; drilled after the exploratory discovery(s); site location usually based on seismic data.
Infill
Re-entry
Drills the known productive portions of the reservoir; site selection usually based on patterns, drainage radius, etc. Existing well re entered to deepen, side track, rework, or recomplete; various amounts of planning required, depending on purpose of re-entry
Overview of the Planning Process
Well planning is an orderly process. It requires that some aspects of the plan be developed before designing other items. For example, the mud density plan must be developed before the casing program since mud weights have an impact on pipe requirements. Fig. 1-2 illustrates a commonly used flow path for a well plan. Bit programming can be done at any time in the plan after the historical data have been analyzed. The bit program is usually based on the drilling parameters from offset wells. However, bit selection can be affected by the rimed plan, i.e., the performance of PCD bits in oil muds. In addition, bit sizing may be controlled by casing drift diameter requirements. Casing and tubing should be considered as an integral design. This fact is particularly valid for production casing. A design criteria for tubing is the drift diameter of the production casing, whereas the production casing can be affected adversely by the packer14
to-tubing forces created by the tubing's tendencies for movement. Unfortunately, these calculations are complex and often neglected. The completion plan must be visualized reasonably early in the process. Its primary effect is on the size of casing and tubing to be used if oversized tubing or packers are required. In addition, the plan can require the use of high strength tubing or unusually long seal assemblies in certain situations. Activities before starting drilling operation Activities undertaken prior to start of drilling operation can be broken down into the following: 1. Release of location. 2. Survey of surface/subsea location. Sometimes the cost can be reduced by a small change in surface location. 3. Civil works and foundation for onshore drill site and soil coring/sea bed survey in case of offshore well. 4. Preparation of Geo-technical order. 5. Preparation of complete well plan/programme. 6. Preparation of bill of material and initiation of purchase procedure, if required. 7. Procedures from obtaining sanction for purchase to receipt of material. 8. Rig allocation and its shifting to the new location.
GEO – TECHNICAL ORDER The various input data are thoroughly analysed and the geo technical order is prepared which provides broad guidelines for drilling of well. G.T.O. furnishes the following details: 1. General data like well name, well no., area, location, water depth, elevation, well type, category, objectives of well, etc. 2. Geological data, which consists of following details depth, age, formation, oil/gas shows, electro logging, etc. 3. Mud parameters consisting of mud type, specific gravity, viscosity, pH, percentage of sand, etc.
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4. Drilling data including casing policy and rise of cement, drilling type, type & size of bits, no. of bits b its expected, RPM of rotary, etc. 5. Remarks, if any.
CASING Importance of casing : To prevent weak formation from collapsing and causing caving of the hole. Serving as a high strength flow conduit to surface for both drilling and production fluids. Protecting fresh water bearing formation getting contaminated from drilling and production fluids. Provide suitable support for wellhead equipment, tubing and subsurface equipment. Provide safe passage for running wire line equipment. Allowing isolated communication with selective perforated formation of interest.
Types of Casing and Tubing Drilling environments often require several casing strings in order to reach the total desired depth. Someof the strings are as follows: • Drive or structural conductor •
Surface
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Intermediate (also known as protection pipe) liners
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Production (also known as an oil string)
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Tubing (flow string)
Fig shows the relationship of some of these casing strings. In addition, the illustration shows some of the problems and drilling hazards that the strings are designed to control. All wells will not use each type of casing. The conditions to be encountered in each well must be analyzed to detennine the types and amount of pipe necessary to drill it. The general functions of all casing strings are as follows:
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segregate and isolate various formations to minimize drilling problems or maximize production furnish a stable well with a known diameter through which future drilling and completion operations can be executed provide a secure means to which pressure control equipment can be attached
Drive Pipe or Conductor Casing. The first string run or placed in the well is usually the drive pipe, or conductor casing. The normal depths range from 100300 ft. In soft-rock areas such as southern Louisiana or most offshore environments, the pipe is hammered into the ground with a large diesel hammer. h ammer. Hard-rock areas require that a large-diameter, shallow hole be drilled before running and cementing the pipe. Conductor casing can be as elaborate as heavy wall steel pipe or as simple as a few old oil drums tacked together.
A primary purpose of this string of pipe is to provide a fluid conduit from the bit b it to the surface. Very shallow fonnations tend to wash out severely and must be protected with pipe. In addition, most shallow fonnations exhibit some type of lost circulation problem that must be minimized. An additional function of the pipe is to minimize hole caving problems. p roblems. Gravel beds and unconsolidated rock will continue to fall into the well if not stabilized with casing. Typically, the operator is required to drill through these zones by pumping viscous muds at high rates. Structural Casing. Occasionally, drilling conditions will require that an additional string of casing be run between the drive pipe and surface casing. Typical depths range from 600-1,000 ft. Purposes for the pipe include solving additional lost circulation or hole caving problems and minimizing kick problems from shallow gas zones. Surface Casing. Many purposes exist for running surface casing, including the following: •
cover freshwater sands
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maintain hole integrity by preventing caving minimize lost circulation into shallow, permeable zones
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cover weak zones that are incompetent to control kick-imposed pressures
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provide a means for attaching the blowout preventers .support the weight of all casing strings (except liners) run below the surface pipe. 17
Intermediate Casing. The primary applications of intermediate casing involve abnormally high formation pressures. Since higher mud weights are required to control these pressures, the shallower weak formations must be protected to prevent lost circulation or stuck pipe. Occasionally, intermediate pipe is used to isolate salt zones or zones that cause hole problems, such as heaving and sloughing shales. Liners. Drilling liners are used for the same purpose as intermediate casing. Instead of running the pipe to the surface, an abbreviated string is used from the bottom of the hole to a shallower depth inside the intermediate pipe. Usually the overlap between the two strings is 300-500 ft. In this case, the intermediate pipe is exposed to the same drilling considerations as the liner. Drilling (and production) liners are used frequently as a cost-effective method to attain pressure or fracture gradient control without the expense of running a string to the surface. When a liner is used, the upper exposed casing, usually intermediate pipe, must be evaluated with respect to burst and collapse pressures for drilling the open hole below the liner. Remember that a full string of casing can be run to the surface instead of a liner if required, i.e., two intermediate strings.
Production Casing. The production casing is often called the oil string. The pipe may be set at a depth slightly above, midway through, or below the 18
pay zone. The pipe p ipe has the following purposes: • • •
isolate the producing zone from the other formations · provide a work shaft of a known diameter to the pay zone protect the production tubing equipment
Tie-back String. The drilling liner is often used as part of the production casing rather than running an additional full string of pipe from the surface to the producing zone. The liner is tied-back or connected to the surface by running the amount of pipe required to connect to the liner top. This procedure is particularly common when 1) Producing hydrocarbons are behind the liner and 2) The deeper section is not commercial.
Setting Depth Design Procedures
'Casing seat depths are directly affected by geological conditions. In some cases, the prime criterion for selecting casing seats is to cover exposed, severe 19
lost circulation zones. In others, the seat selection may be based on differential sticking problems, perhaps resulting from pressure depletion in a field. In deep wells, however, the primary consideration is usually based on controlling abnormal formation pressures and preventing their exposure to weaker shallow zones. The design criteria of controlling formation pressures generally appliesto most drilling areas. Selecting casing seats for pressure control purposes starts with knowing geological conditions such as formation pressures and fracture gradients. This information is generally available within an acceptable degree of accuracy. Prespud calculations and. the actual drilling conditions will determine the exact locations for each casing seat. The principle used to determine setting depth selection can be adequately described by the adage, "hindsight is 20-20." The initial step is to determine the formation pressures and fracture gradients that will be penetrated in the well. After these have been established, the operator must design a casing program based on the assumption that he already knows the behavior of the well even before it is drilled. This principle is used extensively for infill drilling where the known conditions dictate the casing program. Using these guidelines, the operator can select the most effective casing program that will meet the necessary pressure requirements and minimize the casing cost.
WELLHEAD SELECTION Having completed the casing design, we have all the information required to allow us to select a wellhead. A wellhead is a general term used to describe the component at the surface of an oil or gas well that provides the structural and pressure-containing interface for the drilling and production equipment. The primary purpose of a wellhead is to provide the suspension point and pressure seals for the casing strings that run from the bottom of the hole sections to the surface pressure control equipment.While drilling the oil well, surface pressure control is provided by a blowout preventer (BOP). If the pressure is not contained during drilling operations by the column of drilling fluid, casings, wellhead, and BOP, a well blowout could occur. Once the well has been drilled, it is completed to provide an interface with the reservoir rock and a tubular conduit for the well fluids. The surface pressure 20
control is provided by a christmas tree, which is installed on top of the wellhead, with isolation valves and choke equipment to control the flow of well fluids during production. Wellheads are typically welded onto the first string of casing, which has been cemented in place during drilling operations, to form an integral structure of the well. In exploration wells that are later abandoned, the wellhead may be recovered for refurbishment and re-use. Offshore, where a wellhead is located on the production platform it is called a surface wellhead , and if located beneath the water then it is referred to as asubsea wellhead or mudline wellhead. The wellhead must of correct pressure rating, designed for the desired service like H2S and be capable of accommodating all designed and contingent casing strings. Components: The primary components of a wellhead system are:
casing head casing spools casing hangers packoffs (isolation) seals bowl protectors / wear bushings test plugs mudline suspension systems tubing heads tubing hangers tubing head adapters
Having selected a well head, its specifications should be included in the Drilling Programme along with a sectional view of its components c omponents stack up.
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BOP REQUIREMENT When primary control of the well has been lost due to insufficient mud hydrostatic pressure, it becomes necessary to seal the well to prevent an uncontrolled flow, or blowout, of formation fluids. The equipment that seals the well is the blowout preventer (BOP). Types of Blowout Preventers • Annular Blowout Preventers • Annular Preventer • Ram Preventer • Drill pipe Blowout Preventers
Annular (Spherical) Preventers The first preventer normally closed when Shut in procedures are initiated is the annular preventer. The four basic segments of the annular preventer are the head, body, piston, and steel-ribbed packing element . When the preventer's closing mechanism is actuated hydraulic pressure is applied to the piston, causing it to slide upward and force the packing element to extend into the wellbore around the drillstring. The preventer element is opened by applying hydraulic pressure in a manner that slides the piston downward and allows the packing to return to its original position. Ram Preventers Unlike the operational manner of the annular preventer, the ram preventers seal the annulus by forcing two elements to make contact with each other in the annular area. These elements have rubber packing seals that affect the complete closure. Other than the sealing mechanism, ram blowout preventers (pipe, blind, and shear) differ greatly from annular preventers in that each type and size of ram has one function and cannot be used in a variety of applications. 22
• Blind rams seal the well if pipe is not in the hole. The element is
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flatfaced and contains a rubber section. The rams are not designed to effect a seal when pipe is in the hole, although occasionally the pipe will be cut if the blind rams are accidentally closed. Precautions should thus be taken with the blowout preventer control panel to ensure the blind rams cannot be accidentally closed. Shear rams are specially designed blind rams. As the word "shear" indicates, this type of ram will seal if pipe is in the hole by shearing, or cutting, the pipe and sealing the open wellbore.
The requirement of the above mentioned BOPs depends upon the company’s policy and anticipated bottom hole pressures. Surface holes have either no BOP requirement, or will need to use a diverter. div erter.
CEMENTING PROGRAMME The 3 main factors that must be considered at the planning stage are : • Slurry Design • Casing Accesories Selection • Displacement rate & methods SLURRY DESIGN: Cement tests should always be performed on representative samples of cement, additives and mix water as supplied from the rig. Cement tests are detailed in API 10, references a & b. THICKENING TIME: Thickening time tests are designed to determine the length of time which a cement slurry remains in a pumpable state under simulated wellbore conditions of temperature and pressure. The pumpability, or consistency, is measured in Bearden Consistency units (Bc); each unit being equivalent to the spring deflection observed with 2080 gm-cm of torque when using the weight-loaded type calibration device. The measure takes no account of the effect of fluid loss. Thus, thickening times in the wellbore may be reduced if little, or no, fluid loss control is specified in the slurry design. Results should quote the time to reach 70 Bc - generally gene rally considered to be the maximum pumpable consistency. FLUID-LOSS 23
Fluid-loss tests are designed to measure the slurry dehydration during, and immediately after cement placement. Under simulated wellbore conditions, the slurry is tested for filtrate loss across a standardised filter press at differential pressures of 100 psi or 1000 psi. The test duration is 30 minutes and results are quoted as ml/30 min. COMPRESSIVE STRENGTH The measurement of the uniaxial compressive strength of two-inch cubes of cement provides an indication of the strength development of the cement at downhole conditions. The slurry samples are cured for 8, 12, 16 and 24 hours at bottom-hole temperatures and pressures and the results reported in psi. Dynamic measurements using ultrasonic techniques correlate well with API test results, but can lead to over-estimation of the strength. RHEOLOGY Ensuring that the rheological behaviour of the slurry downhole is similar to that specified in the design is essential for effective cement placement. The slurry viscosity is measured using a rotational viscometer, such as a Fann. The slurry sample should be conditioned for 20 minutes in an atmospheric consistometer before measurements are taken. Readings should be taken at ambient conditions and at BHCT when possible. Measurements should be limited to a maximum speed of 300 rpm (shear rate 511 1/s). Readings should also be reported at 200, 100, 60, 30, 6 and 3 rpm. CEMENTING AND CASING HARDWARES Some or all of the following equipment is used during cementing operations. 1. Guide shoes 2. Float Collars 3. Baskets and Centralisers 4. Cement Plugs 5. Multistage Collars
MUD PROGRAMME PROGRAMME The following information should be collected and used when selecting drilling fluid or fluids for a particular well. It should be noted that it is common to utilise two or three different fluid types on a single well. • Pore pressure /fracture gradient plots to establish the minimum / maximum mud weights to be used on the whole well, see Chapters One and Two for details. 24
• Offset well data (drilling completion reports, mud recaps, mud logs etc.) from similar wells in the area to help establish successful mud systems, problematic formations, potential hazards, estimated drilling time etc. • Geological plot of the prognosed lithology. • Casing design programme and casing seat depths. The casing scheme effectively divides the well into separate sections; each hole section may have similar formation types, similar pore pressure regimes or similar reactivity to mud. • Basic mud properties required for each open hole section before it is cased off. • Restrictions that might be enforced in the area i.e. government legislation in the area, environmental concerns etc. Drilling Mud Properties : • MUD WEIGHT OR MUD DENSITY • FUNNEL VISCOSITY • PLASTIC VISCOSITY (PV) • YIELD POINT GEL STRENGTHS • • FLUID LOSS AND FILTER CAKE
SOLIDS CONTROL EQUIPMENT Having decided on the mud system to be used for the well, the mud treatment equipment available on the rigs should be appraised to check compatibility with the selected system. The treatment equipment falls into the four main groups: • Shale shakers(60µ) • Mud cleaners(30µ) • De-sanders and De-Silters(60-15µ) • Centrifuge (1-2µ)
Solids contaminants and gas entrapped in mud can be removed from mud in four stages: • Screen separation: shale shakers, scalper screens and mud cleaner cle aner screens. • Settling separation in non-stirred compartments: sand traps and settling pits. • Removal of gaseous contaminants by vacuum va cuum degassers or similar equipment • Forced settling by the action of centrifugal devices including hydrocyclones (desanders, desilters and micro-cones) and centrifuges.
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BIT AND HYDRAULICS PROGRAMME Bit selection begins with a thorough examination of bit records from offset wells data. The best and worst performance and dull bit grading in formations comparable to the well being designed should be examined, analysed and the used to determine the characteristics of the best performing drill bits. In particular attention should be placed on the details such as the premature failure of bits, reasons drillbits pulled, dull characteristics of inserts: whether the inserts were worn or broken, etc. A drill bit that had broken inserts clearly indicate that the formation should have been drilled with a much harder drillbit. This detailed examination will be explained in the next sections of this chapter. Data required for the correct bit selection include the following: 1. Prognosed lithology column with detailed description of each formation 2. Drilling fluid details 3. Well profile When drilling directional wells the Directional Contractor should be asked to provide an assessment of the required BHA changes, motor requirements and any limitations on bit operating parameters which may impact on the selection of bits. In addition bit characteristics in terms of walk, build and drop tendencies will need to be assessed for their impact on the well path. When using a mud motor in the assembly all tri-cone bits should have a motor bearing system which allows extended use at high motor RPM‘s or a fixed cutter bit should be selected. Due consideration should always be given to the jet system of the bit. When drilling soft shale sections where the major limitations on ROP is bottom hole and cutter cleaning, the use of centre jet, extended jets or lateral jet bits should be considered. There are 3 types of drilling bits: 1. Drag bits 2. Roller cone or rock bits 3. Diamond bits a) PDC (Polycrystalline Diamond Compact) bits b) TSP (Thermally Stable Polycrystalline) bits
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The hydraulics system serves many purposes in the well. Since it is centered around the mud system, the purposes of mud and hydraulics are often common to each other . The hydraulics system has many effects on the well. Therefore, the reasons for giving attention to hydraulics are abundant. The more common reasons are as follows: • •
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control subsurface pressures provide a buoyant effect to the drillstring and casing minimize hole erosion due to the mud's washing action during movement remove cuttings from the well, clean the bit, and remove cuttings from below the bit increase penetration rate size surface equipment such as pumps control surge pressures created by lowering pipe into the well minimize wellbore pressure reductions from swabbing when pulling pipe from the well Evaluate pressure increases in the wellbore when circulating the mud. maintain control of the well during kicks Quite often, these effects are interrelated, which increases in creases the difficulty in optimization.
There are two main theories concerning con cerning how much hydraulic horsepower should be expended at the bit to gain maximum cleaning efficiency. The first theory is the maximum hydraulic horsepower theory, which in practice means expending rd 2/3 of the available HHP at the bit. The alternative theory is the maximum jet impact theory which in practice means expending around 50% of the available HHP at the bit.
EVALUATION REQUIREMENTS In this part of the programme, the evaluation requirements necessary to meet the well objectives should be formatted as follows: • • • • • •
Drilling log requirements Mud logging requirements Coring requirements MWD requirements Electric logging requirements Testing requirements 27
LOG INTERPRETATION OBJECTIVES • The objective of log interpretation depends very much on the user. Quantitative analysis of well logs provides the analyst with values for a variety of primary parameters, such as: • porosity • water saturation, fluid type (oil/gas/water) • lithology • permeability • From these, many corollary parameters can be b e derived by integration (and other means) to arrive at values for: • hydrocarbons-in-place • reserves (the recoverable fraction of hydrocarbons in-place) • mapping reservoir parameters • But not all users of wireline logs have quantitative analysis as their objective. Many of them are more concerned with the geological and geophysical aspects. These users are interested in interpretation for: • well-to-well correlation • facies analysis • regional structural and sedimentary history • In quantitative log analysis, the objective is to define • the type of reservoir (lithology) • its storage capacity (porosity) • its hydrocarbon type and content (saturation) • its producibility (permeability) GAMMA RAY LOG • Gamma Rays are high-energy electromagnetic electromagnetic waves which are emitted by atomic nuclei as a form fo rm of radiation • Gamma ray log is measurement of natural radioactivity in formation verses depth. • It measures the radiation emitting from naturally occurring U, Th, and K. • It is also known as shale log. • GR log reflects shale or clay content. • Clean formations have low radioactivity level. • Correlation between wells, • Determination of bed boundaries, • Evaluation of shale content within a formation, • Mineral analysis, • Depth control for log tie-ins, side-wall coring, or perforating. • Particularly useful for defining shale beds when the sp is featureless • GR log can be run in both open and cased hole 28
Spontaneous Potential Log (SP) • The spontaneous potential (SP) curve records the naturally occurring electrical potential (voltage) produced by the interaction of formation connate water, conductive drilling fluid, and shale • The SP curve reflects a difference in the electrical potential between a movable electrode in the borehole and a fixed reference electrode at the surface • Though the SP is used primarily as a lithology indicator and as a correlation tool, it has other uses as well: – permeability indicator, – shale volume indicator – porosity indicator, and – measurement of Rw (hence formation water salinity).
Neutron Logging • The Neutron Log is primarily used to evaluate formation porosity, but the fact that it is really just a hydrogen detector should always be kept in mind • It is used to detect gas g as in certain situations, exploiting the lower hydrogen density, or hydrogen index • The Neutron Log can be summarized as the continuous measurement of the induced radiation produced by the bombardment of that formation with a neutron source contained in the logging tool which sources emit fast neutrons that are eventually slowed by collisions with hydrogen atoms until they are captured (think of a billiard ball metaphor where the similar size of the particles is a factor). The capture results in the the emission of a secondary gamma ray; some tools, especially older ones, detect the capture gamma ray (neutron-gamma log). Other tools detect intermediate (epithermal) neutrons or slow (thermal) neutrons (both referred to as as neutron-neutron logs). Modern neutron tools tools most commonly count thermal neutrons with an He-3 type detector. Induction Logs are used in wells that do not use mud or water, but oil-based drilling fluids or air, which are nonconductive and, therefore, cannot use electric logs. Induction uses the interaction of magnetism and electricity to determine Resistivity. The Density Log • The formation density log is a porosity log that measures electron density of a formation 29
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Dense formations absorb many gamma rays, while low-density formations absorb fewer. Thus, high-count rates at the detectors indicate low-density formations, whereas low count rates at the detectors indicate high-density formations. • Therefore, scattered gamma rays reaching the detector is an indication of formation Density. Scale and units: The most frequently used scales are a range of 2.0 to 3.0 gm/cc or 1.95 to 2.95 gm/cc across two tracks. A density derived porosity curve is sometimes present in tracks #2 and #3 along with the bulk density ( rb) and correction (Dr) curves. Track #1 contains a gamma ray log and caliper.
Methods of Well Logging: Resistivity Log Basics about the Resistivity: Resistivity: • Resistivity measures the electric properties of the formation, • Resistivity is measured as, R in W per m, • Resistivity is the inverse of conductivity, • The ability to conduct electric current depends upon: • The Volume of water, • The Temperature of the formation, • The Salinity of the formation The Resistivity Log: Resistivity logs measure the ability of rocks to conduct electrical current and are scaled in units u nits of ohm-meters. The Usage: Resistivity logs are electric logs which are used to: • Determine Hydrocarbon versus Water-bearing zones, • Indicate Permeable zones, • Determine Resisitivity Porosity.
Acoustic Log • Acoustic tools measure the speed of sound waves in subsurface formations. While the acoustic log can be used to determine porosity in consolidated formations, it is also valuable in other applications, such as: • Indicating lithology (using the ratio of compressional velocity over shear velocity), 30
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Determining integrated travel time (an important tool for seismic/wellbore correlation), Correlation with other wells Detecting fractures and evaluating secondary porosity, Evaluating cement bonds between casing, and formation, Detecting over-pressure, Determining mechanical properties (in combination with the density log), and Determining acoustic impedance (in combination with the density log).
WELL COST ESTIMATION REASONS FOR COSTING As will be discussed later, there are many elements which comprise the well cost. These range from rig, casing, people, drilling equipment etc. The final sheet summarizing the well cost is usually described as the AFE: “Authorisation For Expenditure”. The AFE is the budget for the well. Once the AFE is prepared, it should then be approved and signed by a senior manager from the operator. The AFE sheet would also contain: project description, summary and phasing of expenditure, partners shares and well cost breakdown. Details of the well will be attached to the AFE sheet as a form of technical justification. justification. There are several reasons for producing a well cost, including: 1. Budgetary control 2. Economics 3. Partners recharging 4. Shareholders The AFE is then used as a document for partners recharging, paying contractors and an overall control on the well spending. FACTORS AFFECTING WELL COSTS Well costs for a single well depend on: 1. Geographical location: land or offshore, country 2. Type of well: exploration or development, HPHT or o r sour gas well 31
3. Drillability 4. Hole depth 5. Well target(s) 6. Profile (vertical/ horizontal /multilateral) 7. Subsurface problems 8. Rig costs: land rig, jack-up, semi-submersible or drillship and rating of rig 9. Completion type 10. Knowledge of the area: wildcat, exploration or development The total well costs for a development drilling programme comprising several wells depend on: • Rig rate • Well numbers and well type • Total hole depth • Well layout and spacing • Specifications of equipment • Target tolerances • Water depth for offshore wells Elements of well cost: 1. Preparatory 2. Manpower 3. Services 4. Materials 5. Project Overheads 6. Regional and Headquarter overheads 7. Depreciation of rig equipments 8. Depreciation of drill pipes
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REFERENCES •
www.wikipedia.com
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Google Images
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Drilling Operations Manual (ONGC)
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www.rigzone.com
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Drilling Engineering - A Complete Well Planning Approach by Neal J. Adams
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Well Engineering & Construction by Hussain Rabia
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