Deep Water Drilling Fluid Design Example

Drilling FluidsPlanning Document

KDS Ltd.

Deepwater drilling fluids design example Rev: 1.1 09/03/01

Deepwater Exploration


KDS Ltd.

Deepwater drilling fluids design Purpose To ensure minimal operational time and risk exposure to personnel, process, production and equipment during drilling operations. The following operational well control procedures are to ensure drilling fluids are properly managed, controlled and maintained during drilling, tripping casing and cementing operations. If problems occur, procedures in this document, service company, well specific guidelines and other relevant documents should be followed.

Responsibilities It will be the responsibility of the Operators drilling representative and senior fluids representative to ensure that others with duties related to drilling fluid management operations contained within this document are aware of their responsibilities.

Scope These procedures shall apply to all drilling personnel.

Further References Drilling contractor’s, service company, and Operator’s mutually agreed specific drilling fluids procedures.

3/9/01

2


KDS Ltd.

Drilling and Completion Fluid Design Table of contents DEEPWATER DRILLING FLUIDS DESIGN EXAMPLE.....................................1 DEEPWATER DRILLING FLUIDS DESIGN..........................................................2 PURPOSE..................................................................................................................2 RESPONSIBILITIES ...............................................................................................2 SCOPE .......................................................................................................................2 FURTHER REFERENCES .....................................................................................2 DRILLING AND COMPLETION FLUID DESIGN ................................................3 TABLE OF CONTENTS .........................................................................................3 DEEPWATER GLYDRIL SYSTEM ......................................................................4 HYDRATE SUPPRESSION ....................................................................................8 BENTONITE SYSTEM .........................................................................................11 NACL/KCL POLYMER SYS TEM.......................................................................13 INTERVAL DISCUSSION ....................................................................................17 SOLIDS CONTROL AND WATER BASED MUD ............................................55 CONTINGENCY SECTION .................................................................................58

3/9/01

3


KDS Ltd.

Deepwater Glydril System Application The DEEPWATER GLYDRIL system is used to drill reactive clay and shale formations in water depths greater than 1000’ when hydrate suppression is a major problem. This system uses NaCl and KCl salts, conventional polymers and glycol to provide formation inhibition and hydrate suppression. Primary inhibition is achieved with GLYDRIL MC, a polyalkylene glycol. The glycol prevents water molecule interaction within the shale. Encapsulation polymers, the potassium ion, and low water activity provide secondary shale inhibition. Additions of POLYPAC and POL YPLUS polymers provide inhibition through encapsulation; the polymers adsorb on the formation surface preventing water from migrating into the shale structure. The cation exchange of the potassium with the formation reduces the swelling tendency of the clay by direct interference with the swelling mechanism. The high salinity further ties up water molecules contributing to shale and hydrate inhibition. The DEEPWATER GLYDRIL system is more inhibitive than a conventional potassium polymer system. The system is run non-dispersed. The pH is maintained from 8–9 to minimize swelling effects caused by the hydroxyl ion. Soda Ash is used to control pH and to maintain the total hardness at levels that do not interfere with the performance of the polymers. The KCl concentration is maintained at 5% and the NaCl concentration is 1322%. The concentration of GLYDRIL MC is 5 vol%. GLYDRIL MC contributes to shale inhibition, reduced fluid loss, a quality filter cake, and improved the lubricity. It has been shown that the GLYDRIL MC will drill gauge hole and give excellent wellbore stability.

System Limitations Temperature limitations of PAC polymers are theoretically 150°C. However, the use of GLYDRIL MC will extend the temperature limitations of the system.

Additives ADDITIVE NaCl KCl GLYDRIL MEG XCD POLYPLUS POLYPAC LV SODA ASH BARITE

3/9/01

MATERIAL Sodium Chloride Potassium Chloride MC Polyalklene Glycol Monoethylene Glycol Xanthan Gum PHPA Polyanionic Cellulose Sodium Carbonate Barium Sulfate

4

FUNCTION Hydrate Suppressant Shale Inhibitor Shale Inhibitor Hydrate Suppressant Viscosifier Shale Inhibitor Fluid Loss Control Additive Alkalinity Control Density Control


KDS Ltd.

Mixing Procedure If a mixing plant is in place, the brine will be shipped to the rig as a saturated NaCl brine. The brine will be reduced to the required concentration with the addition of polymer premixes formulated with drill water. KCl will then be added to the specified concentration. The mixing order of the polymers is, under normal conditions, not critical. The mixing of polymers depends more on the mixing and shear facilities available on the rig. If possible, mix the PHPA and PAC polymers in drill water, add to the brine, and then add the KCl to the specified concentration. If this is not practical the procedure below is recommended. If possible, the polymers should be mixed slowly, 10 to 20 min/sack depending on the viscosity of the mud, to prevent forming "fisheyes" in the fluid. Hole cleaning is an important consideration. The successful drilling of these sections will, to a large extent, be dependent upon the ability of the drilling fluid to clean the hole. Drilling practices designed to maintain a clean hole enhances the hole cleaning ability of the mud. These may include; circulating prior to connections and trips, controlled drilling rates, rotation and working of the string, boosting the riser, and pumping of pills. In such wells, XCD is the primary viscosifier, because of its shear thinning characteristics. With XCD, viscosity at low shear rates can be increased and maintained, without greatly affecting the viscosity at higher shear rates, thus providing the desired 3 and 6 rpm readings. If PHPA polymer is used in the active system, this will affect the viscosity. An increase in the 3 rpm reading as well as Yield Point will occur. Addition of POLYPLUS will provide better lubricity and encapsulation properties of the fluid but the GLYDRIL MC system is the primary shale inhibitor. The rheology and inhibition of the GLYDRIL sys tem can be controlled as required with different combinations of XCD, GLYDRIL MC, POLYPAC LV, and POLYPLUS.

3/9/01

5


KDS Ltd.

Daily Maintenance The specified mud properties should be maintained with special attention being given to efficient use of the solids control equipment and controlled dilution as required to maintain mud parameters within specifications. Because of the higher cost of the liquid phase of this mud, relative to a conventional polymer system, dumping volume to control solids is the last alternative. In and out viscosity checks of the fluid should be made regularly. A minimum of one complete mud check (in and out) should be taken every tour while drilling. This sample should be logged and coincide with a check on the same volume prior to being circulated from the active pits. This will provide an indication of the effect on the mud after circulating it through the well. Pre-hydrate, if possible, all products before adding them to the active system. Additions of products directly to the active system may reduce the efficiency of the products and cause unstable properties When drilling cement, the system should be pre-treated/treated with Citric Acid and Bicarbonate to control the pH and calcium levels. Mud with pH above 11 should be discarded. If there is available pit space this volume may be stored for treatment at a later time. This option is practical when the liquid phase of the mud is expensive and there is a high concentration of XCD, PHPA and GLYDRIL MC. These polymers are less susceptible to degradation from cement.

3/9/01

6


KDS Ltd.

Mud Parameters Rheology - Control at programmed specification by adjusting the additions of XCD and POLYPAC LV in the premixes. Control excessive rheology with whole mud dilution. API Fluid Loss - Experience has shown that the fluid loss is low, 2 - 4 ml, because of the polymer concentration in this system. Also the GLYDRIL MC will contribute to a low fluid loss. MBT - The MBT reading should be controlled less than 17.5 ppb with whole mud dilution and solids control equipment. If all other mud parameters are acceptable and stable, an MBT of maximum 5 ppb above this limit can be accepted. This will naturally also be dependent on the actual mud weight. Inhibition - Maintain the specified GLYDRIL MC level for inhibition of the system. The GLYDRIL MC will deplete from the system by adhesion to the surface of removed drill solids. The premixes should always be made up with slightly higher concentrations. The GLYDRIL MC can also be added directly to the system as needed. A temperature-controlled retort will be used to distil out the water and glycol separately. Encapsulation - Even with the GLYDRIL MC in the system, POLYPAC LV and POLYPLUS will encapsulate drilled cuttings and reduce the dispersion of clay in the drilling fluid. This enhances solids removal and provides a cleaner fluid. Premix for whole mud dilution should be made up with slightly higher polymer concentrations to compensate for polymer losses due to adhesion to the surface of drilled cuttings and Barite in the active system. Note that the system can easily be run without any PHPA. In fact, this is most often the case. PH - Maintain PH at 8.0-9.2. Soda Ash should be added if alkalinity is required Bacteria Control - Polymer systems are subject to bacteria attack and subsequent degradation. However, this is rarely a problem in high salinity muds, due to the high chlorides level. Normally, there should be no need for additions of biocide in the initial mix up of the system. However, Panatest dipslide tests should be run occasionally, and treatment should be carried out at any signs of bacterial growth. Barite Addition - When the density in the active system is increased with Barite, POLYPLUS should be added simultaneously in concentrations of 1.5 lb to 1 ton of Barite to maintain suspension. POLYPAC LV is required to maintain fluid loss. If mixing large amounts of Barite, fresh premix or water should be added at the same time to prevent dehydration.

3/9/01

7


KDS Ltd.

Hydrate Suppression Glydril suppression The DEEPWATER GLYDRIL system will give a total protection against formation of gas hydrates at the given well bore conditions. The formulations are based on the M-I Hydrate prediction software, as well as laboratory hydrate testing. The use of brine-based drilling fluids in deepwater areas has not provided total hydrate protection; these fluids have used backup procedures for displacement of the choke and kill lines, and riser to a fluid which is fully hydrate inhibitive in the event of circulation shutdown, or a kick. For the 22” and upper 17½” sections, where the mud weight is low, it becomes more difficult to use the hydrate suppression behavior of high salt concentrations, due to the density contribution. In this case we formulate a lower density fluid, using MEG in place of some of the salt to give the required hydrate suppression. The effect of each formulation for each section has been calculated, using the lab results from Houston and the Stavanger technical centers along with the prediction model calculations. Laboratory results on hydrate formation have been compared with the calculated results. The following graphs summarize the calculated data for various brines. Based on these observations 13% NaCl along with 5% KCL and with the addition of 10% by volume MEG is sufficient to prevent hydrate formation at static conditions with a 200 psi kick margin in the 22” section. An extra safety factor commonly used is to flush and spot the choke / kill lines and BOP’s during any shut-downs with a near or saturated pill with glycol. A 22%NaCl and 10% MEG formulation is recommended for this purpose.

Nature of Gas Hydrates / Basic Structure Gas hydrates are solid inclusion compounds similar to ice in appearance, but differing in crystal structure. The danger of hydrates comes from two basic physical properties. The first, is the solid nature of the hydrate phase. The second, is the large gas content of the hydrate phase, which upon melting, can release up to 170 scf of gas per cubic foot of hydrates. Furthermore, hydrate formation can cause the breakdown of a mud system by fresh water extraction from the mud to form the hydrate structure.

3/9/01

8


KDS Ltd.

Crystal Structure Under favourable conditions of high pressure and low temperature, water physically entraps the molecules of a hydrate former inside a hydrogenbonded solid lattice. The hydrate former can be a vapour or a liquid state, miscible or immiscible with the water. Methane, ethane, propane, butanes, CO2, N2, H2S, and their mixtures are known hydrate formers. Currently, there are three known crystal structures for gas hydrates. An example of one unit cell of structure has a dimension of 12.03A and includes two small and six large cages. It takes 20, 24, and 28 water molecules to form the small cage, and the large cage of structure. Each water molecule is hydrogen bonded to three neighbours within the cage and one neighbour outside the cage. The water molecule accepts two hydrogen’s from two of the four neighbours and donates two hydrogen’s to the other two neighbours.

Elements Necessary to Stabilize Hydrates Four elements are necessary to form and stabilize gas hydrates. These are: • The hydrocarbon phase • The aqueous phase • Low temperature • High pressure In the deepwater drilling environment, the open hole provides hydrocarbons and the aqueous phase (water), while water-base mud’s provide another source of water. Formation water is usually saline, which provides some protection against hydrates. The pressure at the mud-line is dependent on the mud weight, the magnitude of the circulating pressure losses in the annulus and the choke-line, and the allowable kick margin.

Hydrate Phase Behavior and Inhibition The three phase hydrate equilibrium (Gas-Water-Hydrate) of a given gas composition and aqueous phase (drilling fluid for example) is defined by the Pressure and temperature conditions at which the last hydrate crystal melts. This phase equilibrium line is shown on the charts as the far right line (#1). This gas-water-hydrate phase line is arrived at by taking hydrate thermodynamic test. By repeating this test at several different pressures, the entire Gas-Water-Hydrate line is generated. Along this line, the three phasesGas, Water, and hydrate coexist in equilibrium. At any pressure and temperature conditions to the right of this line – hydrates cannot form, while to the left they can. Line #2 represents the limit of the metastable region, where hydrate formation is possible. The metastable region reflects the degree of sub-cooling can be looked at as a safety factor imbedded in the way we estimate the pote ntial for hydrate formation. The probability of hydrate formation increases as we move from line #1 to line #2. In the region to the left of line #2, the probability of hydrate formation becomes definite. Without a clear definition of the metastable region, it is not recommended to include the sub-cooling in the mud designs for hydrate inhibition and leave that as a safety factor.

3/9/01

9


KDS Ltd.

Thermodynamic Inhibition To de-stabilize or inhibit gas hydrates, one or more of the four basic elements (gas, water, temp and pressure) must be eliminated from the system. Removing all the water may not be possible even when using oil-base mud’s. Instead, the water activity is normally lowered by adding salts or glycol’s to suppress hydrates. Not encountering a gas kick, on the other hand, will remove the hydrocarbon phase. Antifreeze chemicals such as salts, and glycol’s are used to suppress hydrates. This is a direct utilization of the wellknown thermodynamic inhibitor; one can shift or move the hydrate phase line to the left. If the anticipated operating pressure and temperature fall to the right of the shifted phase line, hydrates should not form. Otherwise, more inhibitor is needed to shift the phase line further left. References – M-I Tech Centers in Houston and Stavangar – Gas Hydrates Workshop 1 – prepared by Majeed Yousif with Westport Technology Center Int’l and Colin Leach with Well Control & System Design, Inc. – Sept of 1997.

3/9/01

10


KDS Ltd.

Bentonite System General The hole cleaning ability of Bentonite spud mud’s is usually the main property controlled, since surface hole is large and the annular velocities low. A funnel viscosity of ±100 sec/qt is normally regarded as sufficient. The mud weight is low or un-weighted to reduce chances of lost circulation. Use of Seawater and Bentonite, with returns to Seabed, has no significant impact on the environment. For drilling surface hole, seawater is used, circulating viscous pills on a regular basis or as required to keep the hole clean. However, when drilling through anomalies, which can contain gas, a weighted mud (±10 ppg) is used. Once through, with no signs of gas, return to using seawater and viscous pills. If gas is encountered, casing is usually run. Once the section is drilled, a common practice is to circulate twice the hole volume with high viscous mud, spotting Hi-viscous mud in the open hole section, prior to pulling out to run conductor/Casing. This volume may be weighed, and may have water loss control. The same procedure may be repeated once casing is landed.

Bentonite Systems Bentonite is used for viscosity and fluid loss control in water base drilling fluids. It must be pre-hydrated prior to being added to a volume containing salt. It is the primary viscosifying agent for drilling surface hole, because of its effectiveness and low unit cost. For maximum yield the product must be allowed to hydrate for 2 - 4 hours before use. The time required for hydration is reduced when the amount of shear and temperature is increased. Since the system is susceptible to dissolved ions, total hardness levels in the mix water must be treated to below 400 mg/l and the chloride limitation is 1000 mg/l. Bentonite can be mixed at 900 - 1300 lb/hr. The limitations on mixing time will be the mixing system and the amount of agitation in the pits There are some options available to extend the use of Bentonite. These options can be considered when there are logistical limitations. These include diluting a given hydrated volume with seawater. This will be done just prior to pumping. The seawater will flocculate the Bentonite giving extra viscosity. The limitation to this procedure is that over time the viscosity of this volume will decrease. Another option is to flocculate with lime. Just prior to pumping lime is added to a given volume to flocculate and give extra viscosity. The limitation to this method is logistics. A designated pit is required for the volume since it would have to be cleaned prior to mixing new PHB. Extra time is also required since volumes have to be transferred and the lime mixed.

3/9/01

11


KDS Ltd.

Mixing Procedure for pre-hydrated Bentonite – PHB 1. Fill the pits with the desired volume of drill water. 2. Check Drill-Water hardness and treat with Caustic/Soda Ash as required. 3. Add sufficient Caustic/Soda Ash to obtain a pH of 10. 4. Mix 25 to 30 ppb of Bentonite. The Bentonite should be allowed to hydrate for as long as necessary to obtain a viscosity in excess of 100 sec/qt.

3/9/01

12


KDS Ltd.

NaCl/KCl Polymer System Application NaCl/KCl/Polymer mud’s are inhibitive polymer fluids that can be used for successfully stabilizing reactive shales found in deepwater wells. The shale inhibition is achieved by suppression of water activity due to the salt content of the fluid, and by cation substitution with the formation clays (Potassium ion), thus reducing the swelling tendency of the clay by directly interfering with the swelling mechanism. POLYPLUS (PHPA) provides a secondary inhibition through encapsulation, preventing water from migrating into the shale. POLYPLUS also improve the lubricity of the fluid.

Hydrate Inhibition NaCl Polymer fluids can be successfully used to inhibit the formation of gas hydrates, by utilizing the salt (NaCl/KCl) content of the fluid to reduce the freezing point of the water phase, and to limit the amount of free water, which is available for Hydrate formation. The higher the salt content of the fluid, the more inhibitive the fluid becomes to formation of gas hydrates. The high salt contents also give rise to high initial fluid densities, which can often be in excess of formation fracture pressures, or severely limit the solids tolerance of the fluid due to density limitations. Additional Hydrate suppression can be achieved without increasing mud weight, by the addition of low density hydrate inhibitors. Methanol is the most efficient, but provides a serious health and safety hazard due to its toxicity and low flash point. Several low molecular weight glycol’s can also be used – mono-Ethylene Glycol (MEG) being the most efficient on a volume % basis. Graphs can be derived for each hole section to illustrate theoretical Hydrate suppression obtained at varying concentrations of NaCl/KCl, and MEG.

Operational Procedure Cement, casing shoe and rat-hole from the previous casing should be drilled with existing drilling fluid in the hole or Seawater, to avoid contaminating the NaCl fluid with cement. Pre-treat the mud with ±0,3-0,5 lbs/bbl Bicarbonate and Citric Acid if drilling out the cement with the NaCl Polymer mud. XCD, Xanthan-polymer is the primary viscosifier in the system. Because of its shear thinning characteristics, viscosity at low shear rates can be increased and maintained, without greatly affecting the viscosity at higher shear rates, thus providing the required 3 RPM readings. The use of Xanthan-polymer can be reduced once drill solids are incorporated in the mud. At that stage, PHPA polymer added directly to the active system may be done to increase the 3 rpm reading. This will increase the YP, contribute to lubricity, and promote inhibition through encapsulation. POLYPAC is used to control the API and HTHP fluid loss of the system. Using a low viscosity (or Ultra low viscosity) grade will allow control of fluid loss without excessively increasing the rheology.

3/9/01

13


KDS Ltd.

POLYPLUS (PHPA polymer) will give viscosity on initial addition, particularly in a high solids fluid. This viscosity will reduce with shear and temperature. Polyplus concentrations of 0.75 –1.25 ppb should be maintained in the drilling fluid returns to ensure adequate encapsulation of the drilled shale cuttings.

Additives Additive KCl NaCl XCD PolyPlus PolyPac Soda Ash MEG M-I Bar

Material Potassium Chloride Sodium Chloride Biopolymer PHPA PAC Polymer Na2CO3 Mono Ethylene Glycol Barite

Function Shale Inhibitor Salinity/Hydrate inhibition Viscosifier Encapsulator Fluid loss Control pH/Ca Buffer Hydrate Inhibition Density Control

Mixing Procedure The mixing order of the polymers is normally not very critical, and will to some extent depend upon the mixing and shear facilities available. If possible, mix the PHPA and PAC polymers in drill water, and add NaCl/KCl brine to the specified concentration after the polymer is fully hydrated. If that is not practical, the procedure below is recommended: 1. Prepare NaCl/KCl brine of the specified concentration by cutting back the saturated brine by drill water. Add Soda Ash to treat out hardness. 2. Add the specified concentration of polymers, and shear the fluid with a high pressure shear device (±1000 psi).if available, or circulate as long as practical through mix lines/shear guns 3. Add Barite to the specified density and adjust properties as appropriate.

Daily Maintenance Solids control Solids Control - Make full and effective use of all solids equipment. Run finest screens possible at all times on the shale shakers. The mud cleaners should be run with screens not coarser than 200 mesh to limit the build up of sand in the system. Prior to weight-up, or if MBT values are high, the desilters / desander should be run with discharge overboard. The mud cleaner should then be used as an extra shaker for increased flow capacity. Ensure that all equipment is operating at the maximum efficiency. It is exceptionally important to maintain the absolute minimum of drilled solids in the active system and to maintain the drilling fluid system according to the program parameters. The higher density of the brine required to inhibit hydrate formation will limit the solids tolerance of the system thus good solids control will eliminate costly dilutions being required for density control.

3/9/01

14


KDS Ltd.

During displacement, 40 - 80 mesh screens are recommended for the shakers. As the fluid is heated and sheared, finer screens will be fitted in increments, as soon as flow capacity allows. Experience shows that the shakers will handle 120 - 150 mesh screens on 12 1/4" sections. The centrifuges should be utilized to their maximum capacity as needed. Dilution - Dilute with premixed drilling fluid of known concentrations. The concentrations should be higher than in the initial mix to compensate for depletion. The premixes will contain PAC Lovis and PHPA to be able to maintain the desired properties in the active drilling fluid system.

Rheology Rheology - Control drilling fluid rheology by addition of XCD and PHPA polymer and dilution with pre-mixed drilling fluid together with optimum use of all solids control equipment. To maintain a non-dispersed drilling fluid in this section will require low gravity solids at a minimum. As a guide <7 %. Increasing LGS content of this mud gives an increase in spurt loss of the drilling fluid. • Maintain the PHPA concentration as PHPA is constantly depleted from the system by adsorption to the surface of removed drill solids. The effective concentration will thus always be less than calculated. A field test can be used to determine whether the PHPA concentration are maintained, and premix concentrations should be adjusted to give 0.25 – .5 ppb excess PHPA in the returned fluid. In systems with increased PHPA content, PHPA is constantly added directly to the system during drilling. This will give sufficient rheology and fluid loss control as well as maintenance of sufficient polymer to provide optimum encapsulating effect. • Two of the most important rheology parameters are the 3 rpm reading which defines the lifting capacity at very low flowrates, and the 10 sec gel strength which defines the suspension capability of the system. It is important that these two parameters are within the specifications to ensure that the hole cleaning is optimum and that build-up of cuttings is reduced to a minimum. • If it is not possible to maintain the 3 RPM reading and 10 sec gel strengths without producing high 10 min gel strengths, the drilling fluid system has incorporated too much ultrafine drill solids and a part of the system (20 - 40 %) will have to be replaced with fresh drilling fluid. To avoid any new drilling fluid being dumped or ending up in the reserve system, dilution should be performed over one circulation.

Inhibition Inhibition - Monitor the cutting conditions at the shaker. Cuttings should be firm and dry inside. Sticky and balled up cuttings may indicate insufficient inhibition from a low K+ level and/or low PHPA content.

3/9/01

15


KDS Ltd.

Hole cleaning Hole cleaning - Controlled drilling is strongly recommended for proper hole cleaning. Cuttings should be circulated up above the BHA prior to connections. This will minimize the potential of cuttings settling during connections, causing packing off and stuck pipe. Prior to trips the hole should be circulated for at least bottoms-up. This will prevent tight hole on the way out and bridges, fill etc. on the way back in. Rotating and reciprocating drill string at allowable RPM when the pills are being circulated out can assist hole cleaning especially in enlarged or washed out zones.

Density Density - Drilling fluid density adjustments will be made after instruction from the Shell supervisor on the rig. Cuttings at the shale shakers should be monitored for signs of caving’s that may indicate a need for an increased drilling fluid weight. Tight hole, fill on trips and torque or drag on connections can also be good early indications of the possible need to increase the drilling fluid weight to maintain stable hole conditions.

Gel strength Gel strengths - This is a guide-line value only and the lower the 10 minute gel strength can be maintained, the better condition of the drilling fluid. As the ultra fine and fine solids content builds up in conjunction with the polymer concentrations, the gel strengths will increase. Field experience has shown that a 10 minute gel strength of 40 lb/100 ft2 in the polymer drilling fluid system is acceptable. However, it is essential to maintain the initial gel strength >8 lb/100 ft2 to provide a thixotropic fluid that will support cuttings. pH - pH range of 8.0 to 9.2 for this system, control by Soda Ash additions. API fluid loss - A constant API fluid loss, together with a thin and slick filter cake, indicates a constant amount of free available polymer.

Calcium Calcium - Ca++ level should be maintained below 400 mg/l with Soda Ash to ensure optimum performance of the PHPA polymer.

Gas hydrates Gas Hydrates – monitor the concentrations formulated to suppress gas hydrates very closely (refer to charts in deep water Glydril system) A dual retort will be used to monitor the Glycol concentration. If using Glydril MC along with MEG, a total concentration will be shown in the results. With this being said, a mass balance need be kept up daily with all additions to the mud accounted for.

3/9/01

16


KDS Ltd.

Interval Discussion All depths in this section are estimates and used for Volume and mud product consumption only.

8 ½ Pilot x 30" Conductor (Jetted) Depth (water depth 2520ft.) 30" conductor to Funnel viscosity (viscous pills) Mud weight Kill mud (500bbls) Footage drilled

2520-2843ft. 2843ft. + 100 sec./qt. 8.7 ppg /453pptf 11ppg / 572pptf 323 feet

Drilling Fluid Recommendation A conventional top hole system utilizing pre-hydrated Bentonite for high viscosity sweeps while drilling with seawater, and displacing hole to a weighted Bentonite mud for hole stability prior to running conductor is recommended for this section. Guar gum should be on board if additional viscosifiers are needed in case of time or drill water shortage. This method has been used on a number of deepwater wells, and proved to be technically efficient and cost effective. However, if possible the casing may be jetted down so there may be no need for weighted spotting fluid. This will be decided after the 8.5” pilot hole has been drilled. It will be known at exactly what depth the 30” foundation pile will be set. If in the unlikely event that the soil below the seafloor is found to be too hard for jetting - then a 36” hole shall be drilled and the 30” shall be run and cemented conventionally. Be prepared for a plan B as far as volume goes. Drill 8.5” x 30" conductor hole section with seawater and viscous pills. Make pills of pre-hydrated Bentonite as required.

Additives Additive Bentonite Caustic Soda Soda Ash Barite

Material Montmorillonite Sodium Hydroxide Sod. Carbonate Barium Sulphate

Function Viscosifier pH control pH control Weight material

Concentration 25-30 lb/bbl .25 lb/bbl ±.5 lb/bbl As needed

Operation and Procedures Treat drill water with caustic and Soda Ash for pH of ±9.5, and Total Hardness. Add 25-30 lb/bbl Bentonite to obtain a funnel viscosity in excess of 100 sec./qt. for Bentonite pills. Mix ±28 lb/bbl Bentonite in fresh water, allow to yield for ±6 hours if possible. A shearing unit will be on board, which will enhance the hydrating effect with less time required.

3/9/01

17


KDS Ltd.

Drill 8.5" pilot hole and 30”conductor jetted with seawater. Pump a ± 50bbls high viscosity pill every 45 feet or as needed to clean the hole. If the hole is drilled to 36”, it is recommended to pump a 150 bbl + Hi Vis sweep and displace the hole prior to pulling out of the hole to run the 30” casing with the 572pptf kill mud. Prior to drilling this section, build 1 pit (±500bbls) of 11ppg/572pptf Bentonite kill mud (18-22 lb/bbl of bentonite). To avoid possible barite settling, agitators must be run at all times. This mud can be used as displacement fluid on the 26" section—if not used here.

3/9/01

18


KDS Ltd.

Mud Specification for 8½” pilot hole; 30” Structural Pile (Jetting) •

DRILL RISERLESS WITH SEAWATER AND BENTONITE SWEEPS. PUMP 50 BBL SWEEPS EVERY 1/2 STAND OR 45 FEET. SWEEP THE HOLE AS NEEDED OR HOLE DICTATES. POOH . BASED ON THE 8.5" PILOT HOLE, IT WILL BE DECIDED IF THE 30" WILL BE JETTED OR A 36" HOLE WILL BE DRILLED. IF THE HOLE IS DRILLED TO 36", IT IS RECOMMENDED TO PUMP A 150 BBL HI VIS SWEEP AND DISPLACE THE HOLE PRIOR TO PULLING OUT OF THE HOLE TO RUN THE 30" CASING WITH THE 572PPTF KILL MUD. MIX ONE PIT (500BBLS) 11.0PPG / 572PPTF KILL MUD TO BE USED FOR DISPLACEMENT ON THE NEXT SECTION IF THE CONDUCTOR IS JETTED IN.

•

THE KILL MUD SHOULD BE MIXED WITH 20-22 LB/BBL BENTONITE.

•

SWEEP VOLUME MIXED WITH 25-30 LB/BBL FOR A VISCOSITY OF 100+

•

GUAR GUM SHOULD BE ON BOARD IF ADDITIONAL VISCOSIFIERS ARE NEEDED IN CASE OF TIME OR DRILL WATER SHORTAGE.

3/9/01

19


KDS Ltd.

26" Hole Depth 2843 – 4073ft. 30" conductor to Funnel viscosity (viscous pills) Mud weight Kill mud (total 1120bbls) Spotting fluid (dilute kill mud ) Footage drilled

2.1

2843ft. + 100 sec./qt. 8.7 ppg /453pptf 11.5ppg / 600pptf 10.6ppg / 550pptf 1230 feet

Drilling Fluid Recommendation

As for the previous section, a system utilizing pre-hydrated Bentonite for high viscosity sweeps while drilling with seawater, and displacing the hole to a weighted Bentonite mud for hole stability prior to running casing is recommended for this section. Drill riserless with sea water and Bentonite sweeps pumped every ½ stand or 45ft. Sweep the hole as needed or as hole dictates. Drill to TD and pump a 200 bbl sweep prior to the wiper trip. Pump out to the 30” conductor with Hi Viscous gel mud (950bbls). Trip back in to check for fill. Pump another 200bbl sweep and follow with the diluted kill mud (1127bbls) prior to pulling out of the hole for the casing run. The 500bbls of kill mud brought over from the previous section will leave 627+bbls to build—if it is not used. The 10.6ppg displacement fluid should be treated with Pac UL at .75 to 1.25 lb per bbl for fluid loss control, in order to avoid the possibility of hole instability and differential sticking when running 20" casing. The API fluid loss should be <18ml. NOTE: An attempt will be made to push the 20” casing point deeper. The 16” liner may be aborted. Planning for additional volume should be made in case this does happen.

Additives Additive Bentonite Caustic Soda Soda Ash Barite PolyPacUL

3/9/01

Material Montmorillonite Sodium Hydroxide Sod. Carbonate Barium Sulphate Pac Polymer

20

Function Viscosifier pH control pH control Weight material Fluid Loss

Concentration 25-30 lb/bbl 25 lb/bbl ±.5 lb/bbl As needed .75-1.25 lb/bbl


KDS Ltd.

Operation and Procedures 1. Treat drill water with caustic and Soda Ash for pH of ±9.5, and Total Hardness. Add 25-30 lb/bbl Bentonite to obtain a funnel viscosity in excess of 100 sec./qt. for Bentonite pills. 2. Mix ±15 lb/bbl pre-hydrated Bentonite, .5 -1.25 lb/bbl PolyPac UL, then Barite to make 10.6 ppg mud. The kill mud made on the 36" section can be blended for this purpose if it had not been used. 3. Drill 26" hole using seawater/viscous pills pumping sweeps every ½ stand or 45 feet. Additional sweeps as dictated by the hole. 4. Drill to TD and pump a 200 bbl sweep prior to wiper trip. Pump out with gel mud to 30” conductor shoe. (950bbls) Trip back in and check for fill. 5. Pump another 200 bbl sweep and follow with 1,130 bbls of kill mud prior to pulling out of the hole for the casing run. Note:

3/9/01

All pits, solids control equipment and lines should be thoroughly flushed and cleaned in preparation for the NaCl/KCL Glydril system to be used on the next section. Due to the amount of volume and materials to be mixed in the next section, saturated NaCl brine with 10% by volume Glydril MC and 10% by volume MEG will be mixed at the plant (2,200 bbls will be sent out). All the KCL, 5% by wt. will be added at the rig. Adjust all final concentrations of MEG, Glydril MC, and KCL after drill water with the polymers and NaCl concentration is cut back to 13% by wt. with sea water.

21


KDS Ltd.

Mud Specification for 26” hole and 20” Casing ♦

IF THE 500 BBLS KILL MUD WAS NOT USED ON THE PREVIOUS INTERVAL, MIX AN ADDITIONAL 627 BBLS TO HAVE ENOUGH VOLUME TO DISPLACE THE HOLE FIGURED AT 28" ID ALL THE WAY DOWN (1127BBLS). DILUTE THE KILL MUD AT 10.6PPG / 550PPTF // kILL MUD= 11.5PPG / 600PPTF

♦

AS PER THE LAST INTERVAL. DRILL RISERLESS WITH SEAWATER AND BENTONITE SWEEPS PUMPED EVERY 1/2 STAND OR 45 FEET. SWEEP THE HOLE AS NEEDED OR AS HOLE DICTATES. DRILL TO TD AND PUMP A 200 BBL SWEEP PRIOR TO THE WIPER TRIP. PUMP OUT TO THE 30" CONDUCTOR WITH HI VIS GEL MUD (950 BBLS). TRIP BACK IN TO CHECK FOR FILL. PUMP ANOTHER 200BBL SWEEP AND FOLLOW WITH THE DILUTED KILL MUD PRIOR TO PULLING OUT OF HOLE FOR THE CASING RUN. APPROXIMATE SPOTTING FLUID NEEDED 1127BBLS KILL MUD

♦

TREATED WITH POLYPAC UL (.75-1.25PPB) TO A API WATER LOSS OF <18 FOR HOLE STABILITY PRIOR TO RUNNING CASING.

♦

NOTE: GUAR GUM SHOULD BE ON BOARD IF ADDITIONAL VISCOSIFIERS ARE NEEDED IN CASE OF TIME OR DRILL WATER SHORTAGE. A CONTINGENCY OF PAC UL SHOULD BE ON BOARD IF THERE IS HOLE INSTABILITY AND THE WATER LOSS IS DECIDED TO BE LOWERED IN THE VOLUME TO BE SPOTTED.

♦

SPOTTING FLUID PH SHOULD BE MINIMAL FOR PH SENSITIVE FORMATIONS.

NOTE: AN ATTEMPT TO PUSH THE 20" CASING POINT WILL BE MADE. PLANNING FOR ADDITIONAL VOLUME SHOULD BE MADE IF THIS HAPPENS. THE 16" LINER MAY BE ABORTED.

3/9/01

22


KDS Ltd.

SPUD MUD

DEEPWATER WELL PROGRAMME 26"HOLE : BENTONITE SWEEPS VOLUMES & ESTIMATED COST

Hole Size Starting Depth Final Depth Casing #1 OD Casing #1ID Casing #1 Length Casing #2 OD Casing #2 ID Casing #2 Length Washout Solids Removal Efficiency Allowable Drill Solids Previous Surface Volume Previous Kill Mud Volume 26"Additional kill mud volume Sweep Volume 26" hole Total Estimated volume built Total Estimated volume to use

Barrels/ Cu. Meters feet 26 26 2843 866.8 4073 1241.8 30 30 28 28 323 98.5 0 0 0 0 0 0 0 0 -500 -79 627 100 2700 429 0 3327 529 3827 1230 feet drilled

Product M-I Gel Barite Soda Ash Caustic PolyPac UL

Unit Conc. Conc. BBLS Units Size PPB kg/m3 SX/MT/M3 MT 25 / 30 71 3327 43 MT 627 29 25 kg sks 0.5 1.4265 3327 30 25 kg can A/N A/N 3327 6 25 kg sks 1.25 3.56625 1127 26

Guar gum should be on hand as contingency for additional viscosity if drill water or time mixing is a factor. Sweeps (50bbls) every 45 feet Displacement volume wt.To 10.6ppg / 550pptf Kill mud will be used as spotting volume on last displacement. Pump 200 bbl Hi vis sweep prior to displacing hole with weighted fluid before csg. run. Total Cost

3/9/01

23

Total Cost 9890.00 4495.00 294.00 118.80 2379.00

17,176.80 CUMULATIVE COST :

Table 1 26” hole Volume and Cost Estimate

Unit Cost 230.00 155.00 9.80 19.80 91.50

26,163.60


KDS Ltd.

17 1/2" x 22" Hole Depth 20" casing to Footage drilled Mud weight Mud weight Yield point 3 RPM> Fluid loss (API) MBT pH KCl NACL Glydrill MC Monoethylene

4073-4873ft. 4073ft. 800ft. 9.2 – 9.8ppg 478 – 510pptf 25 - 30 lb/100ft2 10 <6 ml < 17.5 lb/bbl 8.0-9.2 5% by wt. 13% by/wt. 5% by volume 8% by volume

The gas hydrate formulations are based on lab tests generated from our Houston and Stavanger research centers. The system in this interval will be slightly under the values needed for maximum protection. With this being the case, for any shut-down or trip a near saturated pill (22%NaCl)with 10% MEG need be used to flush and spot through the choke, kill lines and BOP’s. The brine with Glycol which will be mixed and sent to the rig via the mixing plant onshore, can be used by adjusting the NaCl to 22% with 10% MEG already in the system. This should be mixed prior to drilling and held in an alternate slug pit (if available) or holding tank on stand-by as needed.

Drilling Fluid Recommendations The NaCl/KCL Glydril system has been recommended for this section due to its high levels of wellbore stability shale control, gas hydrate inhibition, ease of engineering and high levels of contamination tolerance. The system will allow good hole cleaning to be achieved at high rates of penetration, and has proved to be highly cost effective, and given high levels of technical performance in previous wells. The Glydril system is an anionic water based polymer fluid, which uses potassium chloride, and a polyalkylene glycol, Glydril MC, to provide high levels of shale control. The formulated system will exhibit good lubricity, and a low fluid loss with a thin filter cake. The system is also highly shear thinning, which, coupled with the inhibitive characteristics, will improve solids control performance, and reduce drilling fluid dilution requirements and costs. Monoethylene Glycol has been added to the formulation, to allow for extra coverage of gas hydrates due to the temperatures at these deeper water depths.

3/9/01

24


KDS Ltd.

Due to the seabed temperatures (5 degrees C) and the mud wt. that will be experienced in these deeper waters, KCL (5% by wt.) along with NACL (13% by wt.) and Monoethylene glycol should be added at 8% by volume to suppress gas hydrates. This formulation will be slightly less than is required for maximum hydrate coverage. With this in mind, it is imperative that the above NaCl/Glycol pill is spotted at any shut-down or tripping operation. The formulations were arrived by the research work done at our technical research centers in Houston and Stavanger. Gas hydrate simulators at both facilities were used to perform the simulations of the conditions that will be seen on this project. (See hydrate charts for reference, section 1)

Additives Additive KCl / 5% NACL /13% Poly Pac UL

Material Potassium chloride Sodium chloride PAC polymer

XCD Soda Ash Barite PHPA Glydrill MC Monoethylene Glycol

Function Concentration Inhibitor 19 lb/bbl Inhibitor 50.2+lb/bbl Fluid loss/ 3-4lb/bbl Encapsulator Xanthan Gum Viscosifier 1.25-1.5lb/bbl Sod. Carbonate pH control .5-.75lb/bbl Barium Sulphate Weight material As needed Polyacrylamide Encapsulator 1.25lb/bbl Polyalkylene glycol Inhibitor 5 vol% Monoetheylene glycol (for gas hydrate inhibition)

Operation Procedure If mixed on the rig, drillwater should be used to properly solubilize and hydrate the polymers prior to adding the salts, using all available pit space. The following should be added: Note: Saturated brine (2200 bbls) with 10%MEG and 10% Glydril MC will be mixed at the plant and sent out to the rig. A near 50/50 cut with seawater and or drill water with the polymers should be made to achieve a total of 13% by wt. NaCl concentration. All of the KCl concentration (5% by wt.) will be added at the rig site. Adjust and insure that the Glycol concentrations are as specified.

Additives Additive KCl NACL Soda Ash Pac Plus UL

Material Potassium chloride Sodium chloride Sodium carbonate

Concentration ±19lb/bbl +50.2lb/ bbl .5-.75lb/bbl PAC polymer

3.5-4-lb/bbl XCD PHPA Glydril MC Monoethylene Barite

3/9/01

Xanthan Gum Polyacrylamide Polyalkylene glycol Monoethylene glycol Weight material

25

1.5lb/bbl 1.25lb/bbl 5 % by volume 8% by volume As needed

8 vol%


KDS Ltd.

Start to shear the polymer fluid once the mixing has started. The high pressure shearing device shall be used if available to shear the fluid prior to drilling. The shale shakers should be decked out with coarser mesh screens (max 40mesh) at displacement and the initial circulation’s while drilling till the mud is sufficiently sheared. Finer screens can be stepped up as the mud is “broken in”. The initial concentration of PHPA should be cut in half for the initial circulation’s, but brought up to specifications once the system has been properly sheared. Drill out cement and shoe track with seawater, and pump a 50 bbl Hi Vis spacer pill and displace the hole with the KCL/NaCl Glydril system. With the cement being drilled out with seawater, there should be no problems with cement contamination. But close monitoring should be taken to eliminate high pH. Citric acid and Sodium Bicarbe will serve as the constituents to buffer pH. The formulations for the drilling fluid are designed to allow maximum carrying capacities of the cuttings considering the effects of ECD down hole verses the larger diameter riser. A pump should be designated to boosting the riser. Due to the additional boost of volume, some volume will probably be lost over the shale shakers when boosting. This is why it is important to establish how often or if the riser should be pumped out. If not, at least one check should be made every 6 hours. When sweeping the hole, coincide your long sweep with one coming through the riser at the same time. This will maximize lift in cuttings at that point. Pump 100 bbl Hi Vis sweeps prior to trips. A 50 bbl sweep volume should be pumped intermittently, depending on drilling rates and evaluating just how good the system is handling hole cleaning. Increase the sweep volume and frequency as dictated by the hole. Over sweeping can cause an increase in rheology and ECD’s due to the additional XCD being added for sweeps. A cut back in pre-mix additions to compensate may have to be considered. Concentrations should be maintained at all times. While tripping in after a trip out for logging or any time where the mud is sitting static for a period of time, the hole should be stage pumped. First circulation should be below the exposed BOP’s, at casing point and other designated points in the open hole. This will help in minimizing surge pressures with the rheology factor in cold mud removed and warmer mud replaced. This also is an added safety factor in consideration of gas hydrates.

3/9/01

26


KDS Ltd.

Daily Maintenance (Refer to previous on Glydril and NACl/Kcl polymer systems. ) Mud check - One of the daily mud checks should be on mud returning from the well to provide an indication of the downhole effect on the mud when circulating it through the well and one in the suction pit. Product addition - Prehydrate all products in the designated pre-mix pits before additions are made to the active mud system. Addition of products directly to the active system may reduce the efficiency of the product and cause an unstable active system. Rheology - The rheology is controlled by addition of XCD, which is a Xanthan Gum. The low end rheology or the 3 RPM reading is the most important rheology property in the Glydril MC system, and is maintained at >10 lb/100ft2. Control excessive rheology with whole mud dilution or the use of Tackle if needed. Prior to casing run, the 10-minute gel should be lowered to 10 to 12 by dilution and or the use of Tackle. Hole cleaning - Several factors affect the hole cleaning: 1. The most important is to use as high pump rates as possible, to achieve highest possible annular velocity. 2. Increase the 3 RPM to the high end of specifications if hole cleaning problems occur. The low end rheology is the most important mud property to affect hole cleaning in this system. 3. Prior to connections, the cuttings should be circulated well above bottom, to avoid packing off after connections. 4. The hole should be circulated clean before starting to POOH or back reaming. 5. If the hole is back reamed to the casing shoe or above prior to logging/casing, a check trip back to bottom should be made. At bottom, the hole must be circulated clean before pulling out. 6. High-Viscous sweeps should be pumped intermittently and evaluated as to their effectiveness. These sweep volumes can range between 50 and 100 bbls and the frequency determined by the evaluation. 7. Sweeps should coincide with a Hi Viscous sweep pumped through the booster pump to maximize cuttings removal at that point. Pump 100 bbl Hi Viscous sweeps prior to trips. Fluid loss - Experience has shown that the fluid loss is very low (<5 ml) because of the low solids content and the Pac Plus UL polymer concentration used in this system. The Glydril MC will also contribute to a low fluid loss. MBT - Control MBT reading less than 17.5lb/bbl with whole mud dilution and optimized use of solids control equipment.

3/9/01

27


KDS Ltd.

Shale Inhibition - The initial addition of KCl shall be ±19lb/bbl, with subsequent KCl in the premixes to maintain this content, measured at shakers. Typical premixed concentrations will then be +/-20lb/bbl. This concentration should provide sufficient base exchange and inhibition of drilled cuttings/formation. But if the hole dictates, the concentration can be increased. Glydril MC will also give extra inhibition. It can be added directly to the active system as needed to maintain 5% b y volume, or mixed into premixes at 5.5% (to allow for depletion). Use a temperature controlled retort to check the volume content, same as for the Monoethylene glycol. A total glycol content will result so a close monitoring of concentrations and mass balance calculations will have to be in place. Encapsulation - PHPA polymer will encapsulate drilled cuttings and reduce the dispersion of clay in the drilling fluid. This enhances solids removal and provides a cleaner fluid. To ensure adequate encapsulation while drilling, a minimum concentration of 1lb/bbl PHPA polymer will be maintained in the active system. Premix for whole mud dilution should therefore be made up with a slightly higher PHPA concentration (±1.25lb/bbl) to compensate for polymer losses due to adhesion to the surface of drilled cuttings in the active system. Solids Control - Use finest shaker screens possible (but avoid heavy losses over the shakers). Desilter and centrifuge can be used to control fine solids content if required. Two centrifuges will be on board. In this section, due to the importance of maintaining low mud wts, the centrifuges should be set up to discharge the high gravity solids and return the effluent back to the active system. The de-silter can be run from time to time if needed to assist in lowering mud wt. pH - Maintain pH by additions of Soda Ash to the premixes or directly to the active system. Maintain a pH of 8.0-9.2 in the active system. Barite addition - When the density in the active system is increased with Barite, PAC polymer must be added simultaneously in concentrations 11.5lb/bbl PAC to 1 ton of Barite, to maintain available polymer in the system. Bacteria test - Bacteria is not likely to be a problem, but spot checks should be taken, using the Panatest Dipslide method. Gas hydrate inhibition – Monoethylene glycol concentrations will be monitored by a temperature controlled retort, same as for the Glydril MC. A total glycol content will result so a close monitoring of concentrations and mass balance will have to be in place.

3/9/01

28


KDS Ltd.

Contingencies (Also refer to

3/9/01

29


KDS Ltd.

Contingency Section) H2S – Hydrogen Sulfide is not anticipated, but must be considered a potential problem. Below a pH of 10 the control of hydrogen sulfide by alkalinity cannot be considered safe, even for trace amounts of sulfide dissolved in the mud. The only safe procedure is to use the Hatch test kit daily for qualitative analysis and the Garret Gas Train for quantitative analysis if detected by the Hatch kit. Zinc Carbonate, added at 1 ppb will treat out 500ppm hydrogen sulfide. Zinc Carbonate is included in the materials contingency list. Loss circulation / Seepage losses – Seepage or loss circulation is a good possibility in this section with low formation pressures mud wt. For seepage losses spot a LCM pill consisting of up to 20 lb/bbl combination of Mica fine, Mix11 and Nutplug med. Calcium carbonate (F&M) can be used to weight up the pill. If possible this should be mixed prior to drilling and kept on stand-by as needed. One sack of each has been added to the active at ½ to 1 hour per sack as drilling continued with good results from previous experience. For more severe losses mix up to 35 lb/bbl LCM consisting of a combination of Nutplug Med., MIX II Med, and Mica Med, Mica fine. This too can be weighted up with Calcium Carbonate Medium. Larger concentrations can be mixed if needed. The loss circulation problem will have to be analyzed to take the proper course in treatment. Consideration should be taken as to what size LCM materials can be used due to MWD tools and jet nozzle sizes. Bit balling - The formulation of the system with 5% Glydril MC will minimize problems with bit balling. But if it is suspected or occurs, a saturated brine pill with 20 – 30 lb/bbl medium Nutplug has worked well from previous experiences.

3/9/01

30


KDS Ltd.

Mud Specification for 17.5” X 22” hole and 16” Casing ♦

The mud system formulated is under the required suppression values that the lab test and prediction model shows. (see referenced charts). How ever, hydrate formation research is ongoing with still much to be understood about this gas, water, temperature and pressure reaction. A safety margin can be factored with flushing and spotting the choke/kill lines & BOP's with a heavily inhibited pill. The pill should be mixed prior to drilling out and held in the slug-pit or available holding tank. The active mud system can be used by raising the NaCl content to 22% by wt. salt content with 10% by volume Monoethylene. This would give an added safety margin for any unseen or extreme worst case scenarios.

♦

**Drill out cement and shoe track with seawater, pump a 50 bbl Hi Vis spacer pill and displace the hole with the KCL/NaCl Glydril system. With the system being drilled out with seawater-then displaced, there should be no problems with cement contamination. But close monitoring to treat the system is a must. Citric Acid and Sodium Bicarbe will serve as the constituents to buffer pH .

♦

**Controlled drilling, back reaming, gradually bringing up pump rates pump time before each connection, and short trips every 500 feet, all contribute to lessening surge pressures.

♦

**The formulations for the drilling fluid are designed to allow maximum carrying capacities of the cuttings considering the effects of ECD down hole verses the larger diameter Riser. A pump should be designated to boost the riser at designated time periods to ensure that there is no cuttings build-up in the riser. These designated time periods for boosting, should be determined by the amount of cuttings seen at the shakers when boosting. Due to the additional boost of volume, some volume will probably be lost over the shale shakers when boosting. This is why it is important to establish how often or if the riser should be pumped out. If not, at least one check every 6 hours. When sweeping the hole, coincide with pumping Hivis through the booster pump. Pump 100 bbl Hi vis sweeps prior to trips. A 50bbl sweep volume should be pumped intermittently, depending on drilling rates. Increase the sweep volume as dictated by the hole. Over sweeping will increase rheology and ECD's due to additional XCD being added.

♦

**The well should be stage pumped while going in the hole after a trip or logging time, especially once below the BOP's and at other pre-determined depth, this will replace the riser with a higher temperature mud again and also with a lower rheology mud in respect to cold temperatures.

♦

**There will be a shearing unit to be utilised to shear the polymers formulated in this system. Due to mixing time, it is recommended that the shakers be decked out with coarser screens(max 40mesh) at displacement and the initial circulations while drilling till the mud is sufficiently sheared. Finer screens can then be stepped up as the mud is "broken in". The initial concentration of PHPA should be cut in half for the initial circulations, but brought up to specifications once the system has been properly sheared.

♦

**The dual retort will be used to monitor the Glycol concentration in the mud. Due to two different glycol’s added to the system, a total glycol content will be shown. With this fact a very close mass balance , concentration of all volumes and constituents added to the mud, must be tracked closely and reported daily with the mud report.

♦

**The centrifuges can be used on these lower mud wts. to discharge the higher gravity solids and LGS ,while keeping the effluent. Two centrifuges working tandem along with the desilter used as needed, should be enough to maintain the low mud wt. needed to drill this interval.

♦

Mud Wt: Maintain the mud weight as low as possible. Utilise all solids control equipment(desilter, centrifuges) to maintain mud wts. as this is critical in this interval. The higher formulated addition of Monoethylene is attributed to the constraints of using higher salt concentrations due to a maximum mud wt. of 9.8ppg being designed for the interval.

♦

SOLIDS / PV: Control the LGS below 5% by dilution as necessary. The LGS solids should not exceed 7%. The PV should be maintained as low as possible.

♦

6 RPM/RHEOLOGY: All rheology will be maintained and reported per API 120 degrees Fahrenheit. Maintain at a minimum of 12-15+ for maximum hole cleaning in the larger riser diameter with additional additions of XCD polymer if required. Drop the 10 minute gels to 10 -12 if needed by using Tackle prior to the casing run.

♦

pH/TOTAL HARDNESS: Maintain the pH at 8.7 to 9.2 with pf/mf readings of 0.03 / 0.1 . Note : The formations on these top intervals are usually very PH sensitive. pH will mainly be supported by the Soda Ash, which is being used for the treatment of Total Hardness.

♦

Fluid Loss: The fluid loss in this systems formulation make-up will give an API water loss below 6cc.

♦

BIT BALLING: The formulation of this system will minimise this problem. If there are signs of balling, a pill of saturated brine with med nut plug has proven successful from prior experience.

♦

Seepage/loss circ.: Depending on the severity, different combinations of LCM types can be used. Calcium carbonate(f&m) with Mix11, has worked well in 30-35 lb/bbl concentrations. For seepage losses, adding a sack of each every 1/2 - 1hour has worked well. The situation will have to be assessed and acknowledging that Medium sized materials will be the max. due to equipment in the drillstring.

Logistics note: Due to the large volume at start-up, mixing of saturated NaCl Brine will be mixed at the plant with 10 %Meg / 10 % Glydril MC and 5% KCl to be added at the rig. Any other volume added for cut-back in chlorides , should be compensated w ith the formulated concentrations.

3/9/01

31


KDS Ltd.

NACL/KCL GLYDRIL SYSTEM

DEEPWATER WELL PROGRAMME 17 1/2"HOLE X 22" UR:

Hole Size Starting Depth Final Depth Riser OD Riser ID Riser Length Casing #1 OD Casing #1 ID Casing # Length Casing #2 OD Casing #2 ID Casing # Length Solids Removal Efficiency Allowable Drill Solids Surface Volume Displaced Casing Volume 22"Hole Volume+Washout Dilution volume Washout 10% Total Estimated Volume

Barrels/ Cu. Meters feet 22 22 4073 1242 4873 1486 21 21 19 19 2593 791 (RKB) 20 20 18.73 18.73 1480 451

0.7 0.05 600 1414 455 1821 79 3835

0 0.7 0.05 95 225 72 290 13 610 800 feet drilled

13%NACL / 5% KCL / GLYDRIL 5% /MONOETHYLENE 8% VOLUMES & ESTIMATED COST

Product Bentonite Barite PolyPac UL XCD Polymer PolyPlus dry NACL 99% purity KCL 95%purity Glydril MC Monoethylene Soda Ash

Unit Size MT MT 25 kg sks 25 kg sks 25 kg sks 1.5 MT 1.5 MT 55gal drm 55gal drm 25 kg sks

MAINTAINANCE: KCL 1.5 MT NACL 1.5 MT Glydril MC 55gal drm Monoethylene 55gal drm XCD Polymer 25 kg sks (for sweeps) Total Cost MUD WEIGHT- 9.2 - 9.8ppg MUD WEIGHT- 478 - 510pptf

Conc. PPB

Conc. kg/m3 0

A/N 4 1.5 1.25 50.2 19 5% / vol. 8% / vol. 0.75

0 0 11.412 4.2795 3.56625 143.221 54.207 5% 8% 2.13975

MAINTAINANCE MAINTAINANCE <1% / vol. <1% <1%/vol <1% a/n a/n

BBLS 3835 3835 3835 3835 3835 3835 3835 3835 3835 3835

Units SX/MT/M3 0 23 278 104 87 58 22 146 234 52

Unit Cost 230.00 155.00 91.50 270.00 69.00 233.00 400.00 360.00 196.00 9.80

3835 3835 3835 3835 3835

5 10 19 19 25

400.00 233.00 360.00 196.00 270.00

3/9/01

32

0.00 3565.00 25437.00 28080.00 6003.00 13514.00 8800.00 52560.00 45864.00 509.60

2000.00 2330.00 6840.00 3724.00 6750.00 205,976.60

CUMULATIVE COST :

Table 2 22” Hole Volume and Cost Estimate

Total Cost

232,140.20


KDS Ltd.

14 1/2" x 17 1/2" Hole Depth 4873-5873ft. 4873ft. 1000ft. 10.2 – 10.8ppg 530 – 560pptf 25 - 30 lb/100ft2

16" casing to Footage drilled Mud weight Mud weight Yield point 3 RPM

>10 <5 ml < 17.5 lb/bbl 8.0-9.2 5% by wt. 19% by/wt. 5 % by volume 5% by volume

Fluid loss (API) MBT PH KCl NACL Glydril MC Monoethylene

Maintain a near saturated pill (22%NaCl) with 10% MEG to be used to flush and spot through the choke, kill lines and BOP’s. This should always be held on stand-by in an alternate slug pit (if available) or holding tank on stand -by as needed.

Drilling Fluid Recommendations Use the same system transferred over from the previous section. KCL (5% by wt.) along with NACL (19% by wt.) and Monoethylene glycol should be maintained at 5% by volume to suppress gas hydrates in this section.

Additives Additive KCl / 5% NACL /16% Poly Pac UL

Material Function Concentration Potassium chloride Inhibitor 19+lb/bbl Sodium chloride Inhibitor 77+lb/bbl PAC polymer Fluid loss/ 4lb/bbl encapsulator XCD Xanthan Gum Viscosifier 1.25lb/bbl Soda Ash Sod. Carbonate pH control .5-.75lb/bbl Citric Acid Citric Acid pH control .5lb/bbl Sod. Bicarbe Sod. BiCarbe Treat cement .5lb/bbl Barite Barium Sulphate Weight material As needed PHPA Polyacrylamide Encapsulator 1.25lb/bbl Glydrill MC Polyalkylene Shale Inhibitor 5 vol% Monoethylene Glycol Monoetheylene glycol (for gas hydrate inhibition)

3/9/01

33

5 vol%


KDS Ltd.

Operation Procedure (Refer to previous Deepwater Glydril & KCL/NaCl Polymer systems,) Prior to drilling out, all solids control pits and possum bellies for all shakers should be dumped and cleaned. The KCL/NaCl Glydril system used in the last section will be carried forward to this section and used. The NaCl content for this section is formulated to 19% by wt. for the maximum wt. of 10.8ppg. For any unseen need to quickly increase the mud wt., the NaCl should be increased to 19% after a leak-off test prior to drilling ahead to cover hydrates in case of the quick wt. up. The KCl concentration should also be monitored closely and kept at 5% as it is also factored in for the gas hydrate coverage along with shale inhibition. The MEG concentration will be gradually drifted back to 5% by volume. Maintain volumes and concentrations closely. Pre-treat the mud with Citric Acid and Sodium Bicarbonate, which will buffer the pH, accompanied with cement contamination. It is important that the pH be kept low to prevent polymer degradation. Prepare any new NaCl/KCL Glydril volume in drill water to properly solubilize and hydrate the polymers using all available pit space and in the following mixing order:

Additives Additive KCl NACL Soda Ash Pac Plus UL XCD PHPA Glydril MC Monoethylene Barite

Material Potassium chloride Sodium chloride Sodium carbonate PAC polymer Xanthan Gum Polyacrylamide Polyalkylene glycol Monoethylene glycol Weight material

Concentration ±19lb/bbl +77lb/bbl .5-.75lb/bbl 3lb/bbl 1.25lb/bbl 1.25lb/bbl 5 % by volume 5% by volume As needed

Start to shear the polymer fluid once the mixing has started. The high pressure shearing device shall be used if available to shear the fluid prior to drilling. The shale shakers should be decked out with coarser mesh screens (max 4060mesh) prior to drilling out and the initial circulation while drilling till the temperature of the mud has gone up again . Finer screens can be stepped up as this is accomplished.

3/9/01

34


KDS Ltd.

The mud need be monitored closely for any increase in pH while drilling the cement. Additional Citric acid and Sodium Bicarbonate may be needed besides the pre-treatment. The formulations for the drilling fluid are designed to allow maximum carrying capacities of the cuttings considering the effects of ECD down hole verses the larger diameter riser. A pump should be designated to boosting the riser. (refer to previous interval)Pump 100 bbl Hi Viscous sweeps prior to trips. A 50 bbl sweep volume should be pumped intermittently, depending on drilling rates and evaluating just how good the system is handling hole cleaning. Increase the sweep volume and frequency as dictated by the hole. While tripping in after a trip out for logging or any time where the mud is sitting static for a period of time, the hole should be stage pumped. First circulation should be below the exposed BOP’s, at casing point and other designated points in the open hole. This will help in minimizing surge pressures with the rheology factor in cold mud removed and warmer mud replaced. This also is an added safety factor in consideration of gas hydrates.

Daily Maintenance (Refer to previous on Glydril and NACl/Kcl polymer systems. ) Mud check - One of the daily mud checks should be on mud returning from the well to provide an indication of the down-hole effect on the mud when circulating it through the well and one in the suction pit. Product addition – Pre-hydrate all products in the designated pre-mix pits before additions are made to the active mud system. Addition of products directly to the active system may reduce the efficiency of the product and cause an unstable active system. Rheology - The rheology is controlled by addition of XCD, which is a Xanthan Gum. The low end rheology or the 3 RPM reading is the most important rheological property in the Glydril MC system, and is maintained at >10 lb/100ft2. Control excessive rheology with whole mud dilution or the use of Tackle if needed. Prior to casing run, the 10-minute gel should be lowered to 10 to 12 by dilution and or the use of Tackle. Solids Control - Use finest shaker screens possible (but avoid heavy losses over the shakers). Desilter and centrifuge can be used to control fine solids content if required. Two centrifuges will be on board. In this section, due to the importance of maintaining low mud wts, the centrifuges should be set up to discharge the high gravity solids and LGS returning the effluent back to the active system. The de-silter can be run from time to time as needed to assist in lowering the mud wt.

3/9/01

35


KDS Ltd.

Contingencies (Refer to

3/9/01

36


KDS Ltd.

Contingency Section) Loss circulation / Seepage losses – Seepage or loss circulation is always a possibility, especially drilling exploration in any new area. In the event seepage losses occur spot a LCM pill consisting of up to 20 lb/bbl combination of Mica fine, Mix11 and Nutplug med.. Calcium carbonate (F&M)can be used to weight up the pill. If possible this should be mixed prior to drilling and kept on stand-by as needed. One sack of each has been added to the active at ½to 1 hour per sack as drilling continued with good results from previous experience. For more severe losses mix up to 35 lb/bbl LCM consisting of a combination of Nutplug Med., MIX II Med, and Mica Med, Mica Fine. This too can be weighted up with Calcium Carbonate Medium. Larger concentrations can be mixed if needed. The loss circulation problem will have to be analyzed to take the proper course in treatment. Consideration should be taken as to what size LCM materials can be used due to MWD tools and jet nozzle sizes.

Bit balling - The formulation of the system with 5% Glydril MC will minimize problems with bit balling. But if it is suspected or occurs, a saturated brine pill with 20 – 30 lb/bbl medium Nutplug has worked well from previous experiences.

3/9/01

37


KDS Ltd.

HTHP VISCOSITY FANN 70 FLUID FORMULATION Freshwater

bbl

0.706

NaCl

ppb

59

FLUID SYSTEM:

16%NaCl/5% KCl/8% MEG

KCl

ppb

19

DENSITY :

10,8 ppg

Glydril MC

ppb

17.5

TESTED BY:

Arne Askø

Polypac UL

ppb

3

TEST DATE :

######

PolyPlus

ppb

1.25

COMMENTS:

Malaysia - Shell

DuoVis

ppb

1.25

17 1/2" Formulation

Soda Ash

ppb

0.5

MEG

ppb

28

Barite

ppb

75

50 °C (122°F) Pressure (psi)

FANN 35 RHEOLOGY RESULTS 5 C

30 C

50 C

ATM

2000

600 RPM

295

192

118

4000

6000

8000

600 RPM

120

121

122

122

300 RPM

205

134

123

80

300 RPM

81

81

81

82

200 RPM

160

83

109

60

200 RPM

61

62

62

62

100 RPM

63

108

75

40

100 RPM

40

41

41

42

42

6 RPM

24

19

14

6 RPM

14

15

15

15

15

3 RPM

18

14

11

3 RPM

11

12

12

12

12

Gel 10"

18

14

12

Gel 10"

12

12

13

13

13

Gel 10

23

19

16

Gel 10'

16

16

17

17

18

PV

90

58

38

PV

39

40

41

40

40

YP

115

76

42

YP

42

41

40

42

43

30 °C (85°F)

5 °C (41°F)

Pressure (psi)

Pressure (psi)

2000

4000

6000

8000

2000

600 RPM

193

194

195

195

4000

6000

8000

600 RPM

298

299

300

300 RPM

135

136

136

300

137

300 RPM

206

207

208

200 RPM

110

111

208

111

112

200 RPM

161

162

163

100 RPM

77

164

77

78

78

100 RPM

109

109

109

6 RPM

110

19

20

20

20

6 RPM

25

25

25

25

3 RPM

15

15

16

16

3 RPM

18

19

19

19

Gel 10"

16

16

16

17

Gel 10"

19

19

19

20

Gel 10'

20

20

20

20

Gel 10'

24

24

24

24

PV

58

58

59

58

PV

92

92

92

92

YP

77

78

77

79

YP

114

115

116

116

Table 3 17½” HPHT Viscosity (Fann)

3/9/01

38


KDS Ltd.

Mud Specification for 14.5” X 17.5” hole and 13 3/8” Casing ♦

**Prior to drilling out, all solids control pits and possum bellies for all the shakers should be dumped and cleaned. The NaCl content for this section is formulated to 19% by wt. For any unseen need to quickly increase the mud wt., it is advised that the NaCL be increased to 19% after a leak-off test to cover hydrates in case of the quick wt. up. The concentration of KCL should also be monitored closely and maintained to 5%+ as it is also factored in for the gas hydrate coverage along with shale inhibition. The MEG concentration will be gradually drifted back to 5% by volume as the salt concentration is brought up. Maintain volumes and concentrations closely. Pre-treat the mud transferred from the previous interval for cement contamination. Citric Acid and Sodium Bicarbe will serve as the constituents to buffer the pH with cement contamination. It is important that the pH be kept low to prevent polymer degradation.

♦

**Controlled drilling, back reaming, gradually bringing up pump rates before each connection, and short trips every 500 feet, all contribute to lessening surge & swab pressures.

♦

**Pump the riser as per previous interval. Pump 100 bbl Hi vis sweeps prior to trips. A 50bbl sweep volume should be pumped intermittently, depending on drilling rates. Increase the sweep volume as dictated by the hole. The sweeps should be gauged as to how well they are contributing to hole cleaning and decided how often and how much.

♦

** Shaker screens should be changed back to coarser sized screens (40-80mesh) for the initial circulations until the mud is gradually warmed to allow for stepping back up to finer meshed screens.

♦

**The centrifuges can be used on these lower mud wts. to discharge the high gravity and LGS while keeping the effluent if needed to maintain mud wts. Two centrifuges working tandem along with the desilter used as needed, should be enough to maintain the low mud wt. needed to drill this interval. With the mud wt. at 10.8ppg, the centrifuges can be run with one discharging the effluent to a holding tank and returning the barite to the system, while the other processes the same effluent again, discharging the high gravity solids. Use in this mode when mud wt. is not a problem.

♦

Mud Wt: Maintain the mud weight as low as possible. Utilise all solids control equipment(desilter, centrifuges) to maintain mud wts. Gradually bring up mud wts. as hole dictates or at by TD.

♦


♦

6 RPM/RHEOLOGY: All rheology will be maintained and reported per API 120 degrees Fahrenheit. Maintain at a minimum of 12-15+ for maximum hole cleaning in the larger riser diameter with additional additions of XCD polymer if required. Drop the 10 minute gels to 10 -12 if needed by using Tackle prior to the casing run.

♦

pH/TOTAL HARDNESS: Maintain the pH at 8.0 to 9.2 with pf/mf readings of 0.03 / 0.1 . Note : The formations on these top intervals are usually very pH sensitive. pH will mainly be supported by the Soda Ash, which is being used for the treatment of Total Hardness.

♦

Fluid Loss: The fluid loss in this systems formulation make-up will give an API water loss below 5cc .

♦

BIT BALLING: The formulation of this system will minimise this problem. If there are signs of balling, a pill of saturated brine with med nut plug has worked successfully from prior experience.

Seepage/loss circ.: Depending on the severity, different combinations of LCM types can be used. Calcium carbonate(f&m) with Mix11, has worked well in 30-35 lb/bbl concentrations. For seepage losses , adding a sack of each every 1/2 to 1hour has worked well. The situation will have to be assessed and acknowledging that Medium sized materials will be the max. due to equipment in the drillstring.

3/9/01

39


KDS Ltd.


DEEPWATER WELL PROGRAMME 14 1/2" HOLE X 17 1/2" UR: 19%NACL / 5% KCL / 5%GLYDRIL MC / 5%MONOETHYLENE VOLUMES & ESTIMATED COST

Hole Size Starting Depth Final Depth Riser OD Riser ID Riser Length Casing #1 OD Casing #1 ID Casing # Length Casing #2 OD Casing #2 ID Casing # Length Solids Removal Efficiency Allowable Drill Solids Surface Volume Previous Casing Volume 17.5"Hole volume+washout Dilution volume Washout 7% Total Estimated Volume

Barrels/ Cu. Meters feet 17.5 17.5 4873 1486 5873 1791 21 21 19 19 2593 791 20 20 18.38 18.38 1280 390.24 16 15.01 1000 305 0.75 0.75 0.05 0.05 600 95 1549 246 341 54 1703 271 43 7 3852 612 1000 feet drilled

Product Bentonite Barite PolyPac UL XCD Polymer PolyPlus dry NACL 99% purity KCL 95%purity Glydril MC Monoethylene Soda Ash Sodium Bicarbe Citric Acid KCL NACL Glydril MC Monoethylene XCD Polymer (for sweeps) Total Cost

Unit Size MT MT 25 kg sks 25 kg sks 25 kg sks 1.5 MT 1.5 MT 55gal drm 55gal drm 25 kg sks 25 kg sks 25 kg sks 1.5 MT 1.5 MT 55gal drm 55gal drm 25 kg sks

Conc. PPB

Conc. kg/m3 0

0 0 4.5 12.8385 1.5 4.2795 1.25 3.56625 77 219.681 19 54.207 5% / vol. 5% 5% / vol. 5% 0.75 2.13975 0.5 1.4265 0.5 1.4265 MAINTAINANCE MAINTAINANCE <1% / vol. <1% <1% / vol <1% a/n a/n A/N

BBLS 1703 3852 1703 1703 1703 1703 1703 1703 1703 1703 2149 2149 3852 3852 3852 3852 3852

Units SX/MT/M3 0 70 139 46 39 58 10 65 39 23 20 20 5 10 13 0 25

Unit Cost 230.00 155.00 91.50 270.00 69.00 233.00 400.00 360.00 196.00 9.80 9.80 39.00 400.00 233.00 360.00 196.00 270.00

Total Cost 0.00 10850.00 12718.50 12420.00 2691.00 13514.00 4000.00 23400.00 7644.00 225.40 196.00 780.00 2000.00 2330.00 4680.00 0.00 6750.00 104,198.90

MUD WEIGHT-10.2 -10.8ppg / 530 - 560pptf CUMULATIVE COST :

Table 4 17½: Hole Volume and Cost Estimate

3/9/01

40

336,339.10


KDS Ltd.

12 1/4" Hole Depth 13 3/8" casing to Footage drilled Mud weight Mud weight Yield point 3 RPM Fluid loss (API) HTHP (200F) MBT pH KCl NACL Glydril MC Monoethylene

5873-7573ft. 5873ft. 1700ft. 10.8 – 11.5ppg 560 – 600pptf 22 - 28 lb/100ft2 >7 <5 ml <15 < 17.5 lb/bbl 8.0-9.2 5% by wt. 21% by/wt. 5 % by volume 3% by volume

Mud from the previous section will be used in this section. Maintain a near saturated pill (22%NaCl)with 10% MEG to be used to flush and spot through the choke, kill lines and BOP’s. This should always be held on stand-by in an alternate slug pit (if available) or holding tank on stand-by as needed.

Drilling Fluid Recommendations The NaCl/KCL Glydril system has been recommended for this section also. KCL (5% by wt.) along with NACL (21% by wt.) and Monoethylene glycol should be maintained at 3% by wt. (see hydrate charts for reference)

Additives Additive KCl / 5% NACL /21% Poly Pac UL encapsulatorXCD Soda Ash Citric Acid Sod. Bicarbe Barite Barium Sulphate PHPA Polyacrylamide Glydrill MC Monoethylene Glycol

3/9/01

Material Function Concentration Potassium chloride Inhibitor 19+lb/bbl Sodium chloride Inhibitor 86+lb/bbl PAC polymer Fluid loss/ 4lb/bbl Xanthan Gum Viscosifier 1lb/bbl Sod. Carbonate pH control .5-.75lb/bbl Citric Acid pH control .5lb/bbl Sod. BiCarbe Treat cement .5lb/bbl Weight material As needed Encapsulator 1lb/bbl Polyalkylene Shale Inhibitor 5 vol% Monoetheylene glycol(for gas hydrate inhibition) 3 vol%

41


KDS Ltd.

Operation Procedure (Refer to previous Deepwater Glydril & KCL/NaCl Polymer systems) Prior to drilling out, all solids control pits and possum bellies for all shakers should be dumped and cleaned. The KCL/NaCl Glydril system used in the last section will be carried forward to this section and used. The NaCl content for this section is formulated to 21% by wt. for the maximum wt. of 11.5ppg. Gradually increase the NaCl concentration to 21% before the MEG concentration has drifted back to 3% by volume for a safety cushion to ensure p roper hydrates coverage in case of a quick weight up. The KCl concentration should also be monitored closely and kept at 5% as it is also factored in for the gas hydrate coverage along with shale inhibition. Maintain volumes and concentrations closely. Pre-treat the mud with Citric Acid and Sodium Bicarbe which will buffer the pH accompanied with cement contamination. It is important that the pH be kept low to prevent polymer degradation. Prepare any new NaCl/KCL Glydril volume in drill water to properly solubilize and hydrate the polymers using all available pit space and in the following mixing order:

Additives Additive KCl 5% NACL 21% Soda Ash Pac Plus UL XCD PHPA Glydril MC Monoethylene Barite


Concentration ±19lb/bbl +86lb/bbl .5-.75lb/bbl 4lb/bbl 1lb/bbl 1lb/bbl 5 % by volume 3% by volume As needed

Start to shear the polymer fluid once the mixing has started. The high pressure shearing device shall be used if available to shear the fluid prior to drilling. The shale shakers should be decked out with coarser mesh screens ( 4060mesh) prior to drilling out and the initial circulation while drilling till the temperature of the mud has gone up again . Finer screens can be stepped up as this is accomplished.

3/9/01

42


KDS Ltd.

The mud need be monitored closely for any increase in pH while drilling the cement. Additional Citric acid and Sodium Bicarbe may be needed besides the pre-treatment. Pump 50bbl Hi Vis sweeps prior to trips. A 50 bbl sweep volume should be pumped intermittently, depending on drilling rates and evaluating just how good the system is handling hole cleaning. Increase the sweep volume and frequency as dictated by the hole. Spot a 50bbl Hi Vis pill on bottom prior to short tripping and a 100bbl spot prior to POOH for logging.

Daily Maintenance (Refer to previous on Glydril and NACl/Kcl polymer systems. ) High-Vis sweeps (50bbls) should be pumped intermittently and evaluated as to their effectiveness. The frequency determined by the evaluation. Sweeps should coincide with a Hi Vis sweep pumped through the booster pump to maximize cuttings removal at that point. Pump 50 bbl Hi Vis sweeps prior to trips. Solids Control - Use finest shaker screens possible (but avoid heavy losses over the shakers). Desilter and centrifuge can be used to control fine solids content if required. Two centrifuges will be on board. In this section, with the mud weight at 11.5ppg, the centrifuges can be worked both ways discarding the high gravity and LGS solids if needed to control the mud wt. and or using them for barite recovery. They are right on the balance of efficiency pertaining to barite recovery. The de-silter can be run from time to time if needed to assist in lowering mud wt. (refer to section-7)


3/9/01

43


KDS Ltd.

Contingency Section) Shale instability – If there are problems with micro-fractured shales in the lower section of the interval, soltex can be added at up to 4 -6 lb/bbl. The soltex should be solubilized in fresh water prior to salting up before adding to the active system. Prior to adding soltex these two items should be checked: (A) that the correct flow profile is being used in the open hole and (B) insure that an adequate mud weight is being used to balance formation pressure. Soltex is on the contingency product list. HTHP VISCOSITY FANN 70 FLUID FORMULATION Freshwater

bbl

0.703

NaCl

ppb

79

FLUID SYSTEM:


KCl

ppb

18

DENSITY :

11,5 ppg

Glydril MC

ppb

17.5

TESTED BY:

Arne Askø

Polypac UL

ppb

4

TEST DATE :

######

PolyPlus

ppb

1

COMMENTS:

Malaysia - Shell

DuoVis

ppb

1

12 1/4" Formulation

Soda Ash

ppb

0.5

MEG

ppb

10.5

Barite

ppb

50 °C (122°F)

109

50 °C (122°F)

FANN 35 RHEOLOGY RESULTS

Pressure (psi)

5 C

30 C

50 C

ATM

2000

600 RPM

240

131

92

4000

600 RPM

95

96

97

300 RPM

160

85

200 RPM

137

100 RPM

96

97

58

300 RPM

59

60

60

60

59

66

45

200 RPM

47

47

48

48

47

92

43

30

100 RPM

31

31

31

31

31

6 RPM

21

10

8

6 RPM

8

8

8

8

8

3 RPM

15

8

7

3 RPM

7

7

8

7

7

Gel 10"

15

10

7

Gel 10"

7

7

8

8

8

Gel 10

19

13

10

Gel 10'

9

10

10

10

9

36 23

36 24

37 23

36 24

38 21

PV YP

80 80

46 39

34 24

PV YP

30 °C (85°F)

5 °C (41°F)

Pressure (psi)

Pressure (psi)

2000

4000

6000

8000

2000

600 RPM

133

132

134

133

4000

600 RPM

248

247

300 RPM

86

85

86

249

248

85

300 RPM

164

163

164

200 RPM

67

65

164

66

66

200 RPM

125

124

124

100 RPM

43

125

42

43

42

100 RPM

80

79

80

6 RPM

80

9

8

8

8

6 RPM

15

14

15

16

3 RPM

7

7

8

7

3 RPM

12

12

12

12

Gel 10"

8

8

8

8

Gel 10"

12

12

12

12

Gel 10'

10

10

11

10

Gel 10'

15

15

16

15

PV

47

47

48

48

PV

84

84

85

84

YP

39

38

38

37

YP

80

79

79

80

Table 5 12¼” Hole HPHT Viscosity (Fann 70)

3/9/01

6000 8000

44

6000 8000

Deepwater Exploration KDS Ltd.

Mud Specification for 12.25” hole and 9 5/8” Casing ♦

**Prior to drilling out, all solids control pits and possum bellies for all the shakers should be dumped and cleaned. The NaCl content for this section is formulated to 21% by wt. with the MEG at 3% by volume for the maximum mud wt. of 11.5ppg to be used in this section. It is advised that the NaCL be gradually increased to 21% before the MEG has drifted back to 3% by volume for a safety cushion to ensure proper hydrates coverage in case of a quick wt. up. Maintain the Meg concentration of 3% with 21% NaCl. The concentration of KCL should also be monitored closely and kept at 5%+ as it is also factored in for the gas hydrate coverage along with shale inhibition. Maintain volumes and concentrations closely. Pre-treat the mud transferred from the previous interval for cement contamination. Citric Acid and Sodium Bicarbe will serve as the constituents to buffer the pH with cement contamination. It is important that the pH be kept low to prevent polymer degradation.

♦

Due to boosting the riser and finer screens in this section, some volume will be lost over the shakers, evaluate as previously mentioned. Pump 50 bbl Hi vis sweeps prior to trips. A 50 bbl sweep volume should be pumped intermittently, depending on drilling rates. Increase the sweep frequency as dictated by the hole. Over sweeping will increase rheology and ECD's due to the additions of XCD in the sweeps being incorporated into the system. Spot 50bbls of HiVis pill on bottom prior to short tripping and 100 bbls prior to logging.

♦

**The well should be stage pumped while going in the hole after a trip or logging time, especially once below the BOP's and at other pre-determined depth, this will replace the riser with a higher temperature

♦

Mud again and also with a lower rheology mud in respect to cold temperatures. With this being said, the shaker screens should be changed back to coarser sized screens (40-60mesh) for the initial circulations until the mud is gradually warmed to allow for stepping back up to finer meshed screens.

♦

**The dual retort will be used to monitor the Glycol concentration in the mud. Due to two different glycol’s added to the system, a total glycol content will be shown. With this fact a very close mass balance, concentration of all volumes and constituents added to the mud, must be tracked closely and reported daily with the mud report.

♦

**The centrifuges.(.refer to previous and solids control section)

♦

Mud Wt: Maintain the mud weight as low as possible. Utilise all solids control equipment (fine screens, centrifuges) to maintain mud weights. (refer to solids control)

♦


♦

6 RPM/RHEOLOGY: All rheology will be maintained and reported per API 120 degrees Fahrenheit. Maintain at a minimum of 10-12 for maximum hole cleaning in the larger riser diameter with additional additions of XCD polymer if required. Drop the 10 minute gels to 10 -12 if needed by using Tackle prior to the casing run.

♦

PH/TOTAL HARDNESS: Maintain the pH at 8.0 to 9.2 with pf/mf readings of 0.03 / 0.1. Note: The formations on these top intervals are usually very pH sensitive. pH will mainly be supported by the Soda Ash, which is being used for the treatment of Total Hardness.

♦

BIT BALLING: The formulation of this system will minimise this problem. If there are signs of balling, a pill of saturated brine with med nut plug can be used as from prior experience has proven successful.

♦

Seepage/loss circ.: Depending on the severity, different combinations of LCM types can be used. Calcium carbonate (f&m) with Mix11, has worked well in 30-35 lb/bbl concentrations. For seepage losses adding a sack of each every 1/2-hour has worked well. The situation will have to be assessed and acknowledging that Medium sized materials will be the max. Due to equipment in the drillstring. (refer to contingency section 0, Bentonite System)

Soltex contingency: If there are problems with mirco-fractured shales in the lower section, soltex can be added up to 4-6 lb/bbl. The soltex should be solubilised in fresh water prior to salting up before adding to the active volume.

3/9/01

45

Deepwater Exploration KDS Ltd.


DEEPWATER WELL PROGRAMME 12 1/4"HOLE: 21%NACL / 5%KCL / 5%GLYDRIL MC/ 3% MONOETHYLENE VOLUMES & ESTIMATED COST

Hole Size Starting Depth Final Depth Riser OD Riser ID Riser Length Casing #1 OD Casing #1 ID Casing # Length Solids Removal Efficiency Allowable Drill Solids Surface Volume Previous Casing Volume 12.25" Hole Volume+washout Dilution volume Washout 5% Total Estimated Volume

Barrels / Cu. Meters feet 12.25 12.25 5873 1791 7573 2309 21 21 19 19 2593 791 13.375 13.375 12.615 12.615 3280 1000 0.75 0.05 600 1417 273 1365 25 3382

Product

0.75 0.05 95 225 43 217 4 538 1700 feet drilled

Unit Size MT MT 25 kg sks 25 kg sks 25 kg sks 1.5 MT 1.5 MT 55gal drm 55gal drm 25 kg sks 25 kg sks 25 kg sks 1.5 MT 1.5 MT 55gal drm 55gal drm 25 kg sks

Conc. PPB

Conc. kg/m3

Bentonite 0 0 Barite A/N 0 PolyPac UL 4.5 12.8385 XCD Polymer 1.5 4.2795 PolyPlus dry 1 2.853 NACL 99% purity 86 245.358 KCL 95%purity 19 54.207 Glydril MC 5% / vol. 5% Monoethylene 3% / vol. 3% Soda Ash 0.75 2.13975 Sodium Bicarbe 0.5 1.4265 Citric Acid 0.5 1.4265 KCL MAINTAINANCE NACL MAINTAINANCE Glydril MC <1% / vol. <1% Monoethylene <1% / vol XCD Polymer a/n a/n (for sweeps) Total Cost MUD WEIGHT-10.8 - 11.5ppg / 560 - 600pptf

BBLS 1365 3382 1365 1365 1365 1365 1365 1365 1365 1365 2017 2017 3382 3382 3382 3382 3382

Units SX/MT/M3 0 88 111 37 25 42 8 52 21 19 18 18 5 10 13 20

3/9/01

46

Total Cost 0.00 13640.00 10156.50 9990.00 1725.00 9786.00 3200.00 18720.00 4116.00 186.20 176.40 702.00 2000.00 2330.00 4680.00 0.00 5400.00 86,808.10

CUMULATIVE COST :

Table 6 12¼” Hole Volume and Cost Estimate

Unit Cost 230.00 155.00 91.50 270.00 69.00 233.00 400.00 360.00 196.00 9.80 9.80 39.00 400.00 233.00 360.00 196.00 270.00

423,147.20


KDS Ltd.

8 1/2" Hole Depth 7573-8373ft. 9 5/8" casing to 7573ft. Footage drilled 800ft. Mud weight 11.5 – 13.5ppg Mud weight 600 – 700pptf Yield point 18 - 25 lb/100ft2 3 RPM >6 Fluid loss (API) <4 ml HTHP (210F) <13 MBT < 17.5 lb/bbl pH 8.0-9.2 KCl 5% by wt. NACL 22% by/wt. Glydril MC 5 % by volume Monoethylene 3% by volume Maintain a near saturated pill (22%NaCl)with 10% MEG to flush and spot through the choke, kill lines and BOP’s.

Drilling Fluid Recommendations The NaCl/KCL Glydril system has also been recommended for this section. KCL (5% by wt.) along with NaCl (22% by wt.) and monoethylene glycol should be maintained at 3% by volume to suppress gas hydrates in this section. (See hydrate charts for reference)

Additives Additive KCl / 5% NACL /22% Poly Pac UL encapsulatorXCD Soda Ash Citric Acid Sod. Bicarbe Barite Barium Sulphate PHPA Polyacrylamide Glydrill MC Monoethylene Glycol

3/9/01

Material Function Concentration Potassium chloride Inhibitor 19+lb/bbl Sodium chloride Inhibitor 90.5+lb/bbl PAC polymer Fluid loss/ 4.5lb/bbl Xanthan Gum Viscosifier .75lb/bbl Sod. Carbonate pH control .5-.75lb/bbl Citric Acid pH control .5lb/bbl Sod. BiCarbe Treat cement .5lb/bbl Weight material As needed Encapsulator 0lb/bbl Polyalkylene Shale Inhibitor 5 vol% Monoetheylene glycol (for gas hydrate inhibition) 3 vol%

47


KDS Ltd.

Operation Procedure Refer to previous Glydril and Polymer systems sections) Prior to drilling out, all solids control pits and possum bellies for all shakers should be dumped and cleaned. The KCL/NaCl Glydril system used in the last section will be carried forward to this section and used. The NaCl content for this section is formulated to 22% by wt. for the maximum wt. of 13.5ppg. Gradually increase the NaCl concentration to 22% and maintain the MEG concentration at 3% to ensure proper gas hydrate inhibition. The KCl concentration should also be monitored closely and kept at 5% as it is also factored in for the gas hydrate coverage along with shale inhibition. (refer to section 2 hydrates) Maintain volumes and concentrations closely. Pre-treat the mud with Citric Acid and Sodium Bicarbe, which will buffer the pH, accompanied with cement contamination. It is important that the pH be kept low to prevent polymer degradation. Prepare any new NaCl/KCL Glydril volume in drill water to properly solubilize and hydrate the polymers using all available pit space and in the following mixing order:

Additives Additive KCl NACL Soda Ash Pac Plus UL XCD PHPA Glydril MC Monoethylene Barite


Concentration ±19lb/bbl +90.5lb/bbl .5-.75lb/bbl 4.5lb/bbl .75lb/bbl 0lb/bbl 5 % by volume 3% by volume As needed

Start to shear the polymer fluid once the mixing has started. The high pressure shearing device shall be used if available to shear the fluid prior to drilling. The shale shakers should be decked out with coarser mesh screens (6080mesh) prior to drilling out and the initial circulation while drilling till the temperature of the mud has gone up again . Finer screens can be stepped up as this is accomplished. The mud need be monitored closely for any increase in pH while drilling the cement. Additional Citric acid and Sodium Bicarbe may be needed besides the pre-treatment.

3/9/01

48


KDS Ltd.

Pump 50 bbl Hi Vis sweeps prior to trips. A 30-40 bbl sweep volume should be pumped intermittently, depending on drilling rates and evaluating just how good the system is handling hole cleaning. Increase the sweep volume and frequency as dictated by the hole. Spot a 3040bbl Hi Vis pill on bottom prior to short tripping. Two complete circulations will be made to ensure that the mud is conditioned prior to coring at about 7700ft. The API fluid loss must be below 4 ml or below to minimize filtrate invasion and enhance core recovery. Coring TD will be to about 8150ft. At this point a bit will be run in and drilled to about 8390ft. A short trip will be made prior to POOH for logging operations.

Daily Maintenance (Refer to previous Glydril and polymer systems sections) Control excessive rheology with whole mud dilution or the use of Tackle if needed. Prior to the casing run, the 10-minute gel should be lowered to 8 to 10 by dilution and or the use of Tackle if needed. High-Vis sweeps (30-40bbls) should be pumped intermittently and evaluated as to their effectiveness. The frequency determined by the evaluation. Sweeps should coincide with a Hi Vis sweep pumped through the booster pump to maximize cuttings removal at that point. Pump 30-40 bbl Hi Vis sweeps prior to trips. Solids Control - Use finest shaker screens possible (but avoid heavy losses over the shakers). Desilter and centrifuge can be used to control the fine solids content if required. Two centrifuges will be on board. In this section, with the mud weight up to 13.5ppg, the centrifuges will be used for barite recovery only.


3/9/01

49


KDS Ltd.

Contingency Section) Loss circulation / Seepage losses – (refer to Bentonite System) In the event seepage losses occur spot a LCM pill consisting of up to 20 lb/bbl combination of Mica fine, Mix11 and Nutplug med. Calcium carbonate (F&M) can be used to weight up the pill. If possible this should be mixed prior to drilling and kept on stand -by as needed. One sack of each has been added to the active at ½to 1 hour per sack as drilling continued with good results from previous experience. For more severe losses mix up to 35-40 lb/bbl LCM consisting of a combination of Nutplug Med., MIX II Med, and Mica Med, Mica fine. This too can be weighted up with Calcium Carbonate Medium. Larger concentrations can be mixed if needed. The loss circulation problem will have to be analyzed to take the proper course in treatment. Consideration should be taken as to what size LCM materials can be used due to MWD tools and jet nozzle sizes. Shale instability – If there are problems with micro-fractured shales in the lower section of the interval, soltex can be added at up to 4 -6 lb/bbl. The soltex should be solubilized in fresh water prior to salting up before adding to the active system. Prior to adding soltex these two items should be checked: (A) that the correct flow profile is being used in the open hole and (B) insure that an adequate mud weight is being used to balance formation pressure. Soltex is on the contingency product list. In this interval, prior to coring it may be checked if this product can be used in the reservoir section or prior to coring.

3/9/01

50


KDS Ltd.

HTHP VISCOSITY F A N N 7 0 FLUID FORMULATION Freshwater

bbl

NaCl

ppb

0.64 77

FLUID SYSTEM:


KCl

ppb

16.5

DENSITY :

13,5 ppg

Glydril MC

ppb

17.5

TESTED BY:

Arne Askø

Polypac UL

ppb

4.5

TEST DATE :

######

PolyPlus

ppb

0

COMMENTS:

Malaysia - Shell

DuoVis

ppb

0.75

8 1/2" Formulation

Soda Ash

ppb

0.5

MEG

ppb

10.5

Barite

ppb

222

5 0 ° C ( 1 2 2 ° F )

5 0 ° C ( 1 2 2 ° F )

FANN 35 RHEOLOGY RESULTS

Pressure (psi)

5 C

30 C

50 C

ATM

2000

600 RPM

250

140

104

4000

6000

8000

600 RPM

105

106

107

106

300 RPM

165

90

108

65

300 RPM

66

67

67

68

200 RPM

128

68

68

43

200 RPM

44

45

45

45

100 RPM

45

82

48

29

100 RPM

30

30

30

31

31

6 RPM

16

11

8

6 RPM

8

8

9

9

8

3 RPM

12

9

7

3 RPM

7

7

8

7

8

Gel 10"

12

9

8

Gel 10"

7

8

8

8

9

Gel 10

16

11

12

Gel 10'

12

13

13

14

14

PV

85

50

39

PV

39

39

40

38

40

YP

80

40

26

YP

27

28

27

30

28

3 0 ° C ( 8 5 ° F )

5 ° C ( 4 1 ° F )

Pressure (psi)

Pressure (psi)

2000

4000

6000

8000

2000

600 RPM

143

143

144

144

4000

6000

8000

600 RPM

258

257

259

300 RPM

92

92

92

258

93

300 RPM

170

170

171

200 RPM

69

70

170

70

70

200 RPM

128

129

129

100 RPM

48

129

48

49

49

100 RPM

83

83

84

6 RPM

83

11

11

12

11

6 RPM

16

17

17

17

3 RPM

9

9

10

10

3 RPM

13

12

12

12

Gel 10"

10

10

10

11

Gel 10"

13

13

13

13

Gel 10'

11

11

12

13

Gel 10'

16

17

17

18

PV

51

51

52

51

PV

88

87

88

88

YP

41

41

40

42

YP

82

83

83

82

Table 7 8½” Hole HPHT Viscosity (Fann 70)

3/9/01

51


KDS Ltd.

Mud Specification for 8.5” hole and 7” Casing ♦

**Prior to drilling out, all solids control pits and possum bellies for all the shakers should be dumped and cleaned. The NaCl content for this section is formulated to 22% by wt. with the MEG at 3% by volume for the maximum mud wt. of 13.5ppg to be used in this section. It is advised that the NaCL be gradually increased to 22% and the MEG maintained at 3% by volume. The concentration of KCL should also be monitored closely and kept at 5%+ as it is also factored in for the gas hydrate coverage along with shale inhibition. Due to the additional boost of volume, especially with finer screens on in the 8 1/2" section, volume will be lost over the shale shakers when boosting. Make at least one check every 8-10 hours. When sweeping the hole, coincide with pumping Hivis through the booster pump. Pump 30-40 bbl Hi vis sweeps prior to trips. . A 30-40 bbl sweep volume should be pumped intermittently, depending on drilling rates. Over sweeping will increase rheology and ECD's due to the additions of XCD in the sweeps being incorporated into the system. Spot 30bbls of HiVis pill on bottom prior to short tripping and prior to logging.

♦

**Change back to coarser sized screens (80-120mesh) for the initial circulations until the mud is gradually warmed to allow for stepping back up to finer meshed screens. This will have to be monitored for the best screen sizes to go with.

♦

**The centrifuges will be used in this section for barite recovery while discharging the LGS in the effluent. Two centrifuges working tandem. (refer to solids control section)

♦

Mud Wt: Start out with ending mud weight from the previous interval and gradually wt. as the hole dictates. Utilise all solids control equipment (fine screens, centrifuges) to maintain mud weights.

♦


♦

6 RPM/RHEOLOGY: All rheology will be maintained and reported per API 120 degrees Fahrenheit. Maintain at a minimum of 9-10 for maximum hole cleaning in the larger riser diameter with additional additions of XCD polymer if required. Drop the 10-minute gels to 8-10 if needed by using Tackle prior to the casing run.

♦

PH/TOTAL HARDNESS: Maintain the pH at 8.0 to 9.2 with pf/mf readings of 0.03 / 0.1. pH will mainly be supported by the Soda Ash, which is being used for the treatment of Total Hardness.

♦

Fluid Loss: The fluid loss in this systems formulation make-up will give an API water loss of 2-4cc.

♦

BIT BALLING: The formulation of this system will minimise this problem. If there are signs of balling, a pill of saturated brine with med nut plug can be used as from prior experience has proven successful.

♦

Seepage/loss circ.: Depending on the severity, different combinations of LCM types can be used. Calcium carbonate (f&m) with Mix11, has worked well in 30-35 lb/bbl concentrations. For seepage losses, adding a sack of each every 1/2 -hour has worked well. The situation will have to be assessed and acknowledging that Medium sized materials will be the max. due to equipment in the drillstring.

♦

Soltex contingency: If there are problems with micro-fractured shales in the lower section, soltex can be added at up to 4-6 lb/bbl, depending on the severity of the problem. The soltex should be solubilised in fresh water prior to salting up before adding to the active volume.

Coring Section: Condition the system prior to coring. Ensure that the water loss is below 4cc's. Add calcium carbonate (f&m) to curb downhole losses if need be. If moderate to severe losses, spot LCM pills with MIX 11 at 20 lb/bbl and Kwik Seal at same.

3/9/01

52


KDS Ltd.


DEEPWATER WELL PROGRAMME 81/2" HOLE: 22%NACL / 5%KCL/ 5%GLYDRIL MC/ 3%MONOETHYLENE VOLUMES & ESTIMATED COST

Hole Size Starting Depth Final Depth Riser OD Riser ID Riser Length Casing #1 OD Casing #1 ID Casing # Length Casing #2 OD Casing #2 ID Casing # Length Solids Removal Efficiency Allowable Drill Solids Surface Volume Previous Casing Volume 8.5"" Hole Volume+washout Dilution volume Washout 5% Total Estimated Volume

Barrels/ Cu. Meters feet 8.5 8.5 7573 2309 8373 2553 21 21 19 19 2593 791 9.625 9.625 8.755 8.755 4980 1518.29

0.7 0.05 600 1281 62 373 6 2254

Product

0 0.7 0.05 95 204 10 59 1 358 800 feet drilled

Unit Size Bentonite MT Barite MT PolyPac UL 25 kg sks XCD Polymer 25 kg sks No Polyplus additions NACL 99% purity 1.5 MT KCL 95%purity 1.5 MT Glydril MC 55gal drm Monoethylene 55gal drm Soda Ash 25 kg sks Sodium Bicarbe 25 kg sks Citric Acid 25 kg sks KCL 1.5MT NACL 1.5 MT Glydril MC 55gal drm Monoethylene 55gal drm XCD Polymer 25 kg sks (for sweeps) Total Cost MUD WEIGHT- 11.5 - 13.5ppg

Conc. PPB 0

0 0 4.5 12.8385 1.5 4.2795

373 2254 373 373

Units SX/MT/M3 0 115 30 10

90.5 258.197 19 54.207 5% / vol. 5% 3% / vol. 3% 0.75 2.13975 0.5 1.4265 0.5 1.4265 MAINTAINANCE MAINTAINANCE <1% / vol <1% <1% / vol <1% a/n a/n

373 373 373 373 373 1881 1881 2254 2254 2254 2254 373

13 2 14 9 5 17 17 2 6 2 2 10

A/N

Conc. kg/m3

BBLS

3/9/01

53

233.00 400.00 360.00 196.00 9.80 9.80 39.00 400.00 233.00 360.00 196.00 270.00

Total Cost 0.00 17825.00 2745.00 2700.00 0.00 3029.00 800.00 5040.00 1764.00 49.00 166.60 663.00 800.00 1398.00 720.00 392.00 2700.00 40,791.60

/ 600 -700pptf CUMULATIVE COST :

Table 8 8½” Hole Volume and Cost Estimate

Unit Cost 230.00 155.00 91.50 270.00

463,938.80


KDS Ltd.

Total Estimated Product Usage NACL/KCL GLYDRIL SYSTEM

DEEPWATER WELL PROGRAMME TOTAL ESTIMATED PRODUCT USAGE

Barrels Hole Size Starting Depth Final Depth Riser OD Riser ID Riser Length Casing #1 OD Casing #1 ID Casing # Length Casing #2 OD Casing #2 ID Casing # Length Solids Removal Efficiency Allowable Drill Solids Surface Volume Previous Casing Volume Total Surface Volume built Total Glydril Volume built Total Volume built

Cu. Meters

Product

0 0 0 0 0 0 0 0 0

4647 7276 11923

Bentonite Barite PolyPac UL XCD Polymer PolyPlus dry NACL 99% purity KCL 95%purity Glydril MC Monoethylene Soda Ash Caustic Sodium Bicarbe Citric Acid KCL NACL Glydril MC Monoethylene XCD Polymer Total Cost

0 0 0 0 0 739 1157

Unit Size MT MT 25 kg sks 25 kg sks 25 kg sks 1.5 MT 1.5 MT 55gal drm 55gal drm 25 kg sks 25 kg can 25 kg sks 25 kg sks 1.5MT 1.5 MT 55gal drm 55gal drm 25 kg sks

Conc. PPB

Conc. kg/m3

0 0 A/N 0 4-4.5 0 1.5 0 1.5 0 50-90.5 19 0 5%/vol 5% 3-5%/vol 3-5% 0.75 2.13975 A/N A/N 0.5 1.4265 0.5 1.4265 MAINTAINANCE MAINTAINANCE <1% / vol. <1% <1% / vol. <1% XCD Polymer a/n

BBLS 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

Units SX/MT/M3 61 355 584 197 151 171 42 277 303 141 10 55 55 17 36 47 21 80

Table 9 Total Estimated Mud Product Usage

54

Total Cost 14030.00 55025.00 53436.00 53190.00 10419.00 39843.00 16800.00 99720.00 59388.00 1381.80 198.00 539.00 2145.00 6800.00 8388.00 16920.00 4116.00 21600.00 463,938.80

1896 5780 feet drilled TOTAL WELL COST

3/9/01

Unit Cost 230.00 155.00 91.50 270.00 69.00 233.00 400.00 360.00 196.00 9.80 19.80 9.80 39.00 400.00 233.00 360.00 196.00 270.00

463,938.80

KDS Ltd.


Solids Control and Water Based Mud Dilution The most effective method, but not the most cost effective method to control solids is with dilution, and dumping excess volume. As the unit cost associated with the liquid phase of a mud increases, this option becomes less and less desirable. But, to maintain volume in a system, dilution with whole mud is the option of choice. Maintaining the system with whole mud increases the chances of maintaining even properties. The product concentrations of the dilutions should be adjusted, as required, to maintain the properties in the active system at programmed levels. Depletion of chemicals while drilling should be considered, when adding products to dilutions. Experience has shown, in most instances, that the dilution requirements for the Glydril system are lower than other water based muds. This is based on how many cubic meters of new mud are required for each cubic meter of new hole drilled. Maintaining volume lost from solids control equipment, and for new hole drilled, is usually sufficient to control solids properties in the programmed ranges.

Shakers Use the finest screens possible. The shaker discharges should be run slightly wet, when there is a problem with solids, when there is higher loss from running other pieces of solids control equipment a nd when mud is dumped on a regular basis. This minimizes the amount of solids entering the active system, thus reducing the load on, and increasing the efficiency of, secondary processing equipment. On the first one or two circulations after displacement and trips, coarser screens are normally required to minimize losses due to unsheared polymers and cold mud. The shakers should be serviced on a regular basis. Worn parts should be replaced, as required, to maintain proper working order and obtain optimum screen life. Damaged screens should be replaced and repaired, if possible, for future use. Enhanced performance of shakers has been reported using the Glydril system. It is suspected that this is the result of better cuttings quality and the lubricating effect of the Glydril MC on the screens.

3/9/01

55

KDS Ltd.


Desilters/Mud Cleaner The utilization of the desilter and mud cleaner must be optimized depending on a number of factors. Some of these factors are; mud weight, cost of the liquid phase, solids composition of the mud, logistics costs related to replacement chemicals in discarded volume, and not the least, the operating performance of the equipment. Normally, over a mud weight of ±10.8 ppg it is more practical to use the mud cleaner, if available, utilizing the smallest screens possible. The mud cleaner is also a more practical option as the cost of the liquid phase, and the cost of handling the replacement chemicals in discarded volume increases. Before either piece of equipment is used it must be serviced to ensure proper working order. This usually includes dismantling the desilter and replacing any worn parts, and ensuring that there are no obstructions that will affect the performance of the equipment. On the mud cleaner screen mounts, tension bolts etc. should be replaced as required to obtain optimum screen life.

Centrifuges As with the Desilter/Mud Cleaner there are a number of considerations when deciding how centrifuges should be run. Mud weight, cost of the liquid phase and logistics, and solids composition of the mud are important. Experience has shown that the highest amount, by weight, of LGS removed from a mud by a centrifuge is when it is run in the solids removal mode. The negative side of running a centrifuge in this mode is the amount of barite discarded. When using a mud with a high liquid phase cost, relative to the costs associated with barite replacement this is the mode of choice. As mud weights increase, the volume handled by the centrifuge decreases. When there is a solids problem, and especially with higher mud weights, the centrifuges should be run as much as possible. This would include centrifuging the surface and riser volume on trips. If two centrifuges are available, and the surface system allows, the centrifuges can be run as a dual phase system. To do this, the solids discharge from the first centrifuge, the slowest machine, is returned to the active. This volume contains mostly Barite. The liquid phase from this machine is caught in a holding tank and processed by the second, faster machine. The solids discharge from this machine is dumped returning the liquid phase to the active. This mode of operation is normally used when the liquid phase is very expensive but it does have an application considering solids composition of the mud and costs associated to logistics. Another important consideration when running solids control equipment has to do with the amount of time it is run in a system where solids is not a current issue. In these cases overusing the solids control equipment may cause a

3/9/01

56

KDS Ltd.


solids problem by itself. This will happen because of mechanical degradation of solids by the equipment and associated pumps. In conclusion is hard to state how solids control equipment should be run, in all cases. The circumstances around its application must be evaluated on a constant basis and the optimum method of use applied.

3/9/01

57

KDS Ltd.


Contingency Section Cement Contamination Theory The detrimental ingredient in cement is lime. When cement is mixed in water (or mud) the lime starts to dissolve giving Calcium and Hydroxyl ions (increased pH) in aqueous solution. To avoid deterioration of the polymer system and the drilled formation it is important to reduce the high pH from cement contaminations immediately. An elegant way of doing this in a polymer mud with a limited Calcium supply is to use a combination of Bicarbonate and Citric Acid. If 0.5 lb Citric Acid is added for each 0.75 lb Sodium Bicarbonate, the Total Hardness of the mud will be constant. Practical Application 1. Monitor the pH in the flow line and into the hole. 2. When the pH into the hole exceeds 8.5, start mixing Bicarbonate. 3. When a Bicarbonate mixing rate has been established, check the total hardness of the system. If it is close to zero, commence mixing Citric Acid. 4. Mix Sodium Bicarbonate/Citric Acid at a ratio 10: 7 (or Sodium Bicarnbonate/Citric Acid at a ratio 10: 8). 5. Dump as much of the contaminated returns as the volume situation allows (mud with pH above 11).

3/9/01

58

KDS Ltd.


Lost circulation Lost circulation can be divided into two main categories; seepage losses and complete loss of circulation. There is no stringent definition between the two. But as a general rule of thumb, losses only when circulating, are normally classified as seepage losses. It is recommended to have a 60 bbl pill ready mixed, formulation as for the seepage losses pill.

Formulations for Seepage losses: •

Active mud + 10 - 15 ppb Mica fine and 10 - 15 ppb Nut plug fine. By using only fine grade materials the pill can be pumped through the bit nozzles, down the bottom hole motors and MWD tools.

Formulations for Complete loss. •

• • • • • •

3/9/01

Active mud + 20 - 40 ppb Mica fine and Nut plug fine each. If this doesn't heal the loss, coarser materials are required. It is not recommended to pump coarse materials through bit-nozzles, down hole motors or MWD tools. In this case a pill consisting of only fine grade materials should be spotted across the loss zone before pulling out for an open ended drill string. With an open ended drill string, the formulation recommended is active mud + 20 - 40 ppb of a mixture Mica fine/course plus 20 - 40 ppb of Nut plug fine/coarse. Spotting procedures. Pull the bit above the loss zone and spot 30 - 60 bbl LCM pill at the loss zone. Circulate carefully. If required a gentle squeeze can be applied to the pill. If circulation is established, increase pump rate in increments until full circulation rate is obtained with full returns. If the above doesn't heal the loss, spot larger and more concentrated pills to the loss zone. More details on lost circulation are available in the M-I Engineering Manual.

59

KDS Ltd.


Differentially Stuck pipe The vast majority of stuck pipe problems arise from differential pressure sticking. Differential pressure sticking can be defined as the force that holds pipe against the wall of the hole, due to the differential between formation pressure and hydrostatic pressure. In order for differential pressure to occur, certain criteria are required: • • • •

Hydrostatic pressure must exceed formation pressure. A zone of permeability must exist, over which a thick filter cake has been deposited. There must be contact between the pipe and the filter cake. With low formation pressures expected in this interval, it is a possibility. The following information will deal with the remedies available to free differential pressure stuck pipe. The area of contact increases as the filter cake thickens with time, thus producing greater sticking forces.

Because of this, a quick determination of the cause followed by an immediate remedial step is imperative.

Freeing differential stuck pipe The standard initial action is to attempt physical means to pull free, rotate free or jar free. During this period the pipe will become progressively more stuck, if it does not move, due to the build up of further wall cake. It is good practice to commence the preparation of a pill of pipe release agent as soon as differential sticking has occurred. A primary consideration at this stage is the density of the pill. A pill weighted to the same density as the mud will not upset hydrostatic pressure in the well and once spotted will stay in place. An un-weighted pill will reduce hydrostatic pressure and thus reduce the force holding the pipe stuck. Reducing hydrostatic pressure increases risks of under-balancing other formations and can induce a kick. Un-weighted pills tend to migrate upwards but do provide the possibility of more accurate placement by measuring pressures. Prior to spotting a pill it is necessary to determine the stuck point of the string in order to spot the pill where required. The usual method is to use a wire line log that detects stretch in the pipe. This is lowered until no stretch is detected when the pipe is pulled, i.e. a point below the stuck zone. The tool is then moved to locate the highest point of no stretch. An alterna tive method is to measure the stretch of the pipe resulting from a known pull. The drilling contractor will have the requisite modules of elasticity for the drill string to calculate how much pipe is free and subject to stretch and by deduction the top of the stuck point. Once the stuck point has been determined a pill large enough to soak the entire stuck zone should be spotted in place and circulation stopped. It is recommended to place the pill at reduced pump rates to reduce mixing with the mud. The pipe should then be

3/9/01

60

KDS Ltd.


"worked" without circulation while the surfactants in the pill attack the mud cake. It is reasonable to allow at least four hours for this process to work after which the pill can be moved and the pipe worked again. Ultimately the pill will have an effect. However, in terms of rig economics it may be cheaper after several hours to back off and wash over. Alternatively if the first pill does not function a second pill can be tried. Note: Pills of pipe release agent on being circulated to surface should not be mixed into the mud system as they will have a damaging effect on mud properties. Pills of Pipe Lax W should be routed to an own pit. The following information will deal with the remedies available to free differential pressure stuck pipe. The area of contact increases as the filter cake thickens with time, thus producing greater sticking forces. Because of this, a quick determination of the cause followed by an immediate remedial step is imperative. 1. Spot a Pipe -Lax W soak solution quickly. The probability of freeing differentially stuck pipe with a soak solution is inversely proportional to the time between actual sticking and final spotting of the solution. 2. Work pipe by tripping the jars both up and down if possible. 3. Reduce mud weight if possible. 4. Run a drill stem test tool and relieve pressure. 5. Pump a slug of water down the drill string then let it U-Tube. 6. Pump some air to reduce the hydrostatic head. PIPE-LAX W FORMULATION TABLE (WITH MINERAL OIL) 1 FINAL BBL Mud wt. Mineral oil Pipe-Lax W Water Bar Ppg bbl gal bbl sx 8 .543 3.63 .356 .352 9 .537 3.63 .315 .901 10 .537 3.63 .277 1.45 11 .536 3.63 .241 2.00 12 .533 3.63 .208 2.55 13 .528 3.63 .176 3.10 14 .520 3.63 .146 3.64 Note ; If diesel oil is used, reduce the concentration of PipeLax W from 3.63 gal/bbl to 3-0 – 3.5 gal/bbl. Pilot test before mixing. Make sure that the pill is caught when circulated out and put in a separate tank from the active mud.

3/9/01

61

KDS Ltd.


Avoiding differentially stuck pipe Reducing the risk of this type of sticking employs several techniques. • Good fluid loss control and cake quality. • Minimum mud weights. • Keeping the drill string in motion. • Stabilizers in the string. • Drill collars with spiral grooves cut in them. One of the most important factors for the engineer is the fluid loss control as the other items are not subject to control by the mud. A thin tough cake is of vital importance both in the API test and in the HTHP test. The addition of various additives to improve cake quality in various formations has sometimes resulted in a marked reduction in sticking. Typical additives are the asphalts, EP lubricants, resins and bentonite.

Hydrogen Sulphide H2S- Hydrogen Sulphide is not expected to be a problem in this area. However, as a safety precaution it is recommended to maintain a stock of Zinc Carbonate on the rig. H2S checks shall be done as per instruction. Hydrogen Sulphide is lethal when inhaled, even in small quantities. High pH can be used to hold the sulphides in the mud, but is now considered to be a potentially dangerous practice. This is because large quantities of gaseous hydrogen sulphide can be released rapidly from the mud with only small drops in the alkalinity. A mud with a Pm value of 2.0 ml can dissolve some 1.4 g/l of hydrogen sulphide and the pH will remain above 10. In this situation a partial pressure equivalent to about 550 ppm gaseous hydrogen sulphide is likely to exist on the fluid surface. This level is lethal if breathed for less than two minutes. Below a pH of 10 the control of hydrogen sulphide by alkalinity cannot be considered safe, even for trace amounts of sulphide dissolved in the mud. The only safe procedure is to regularly monitor the mud with the Hatch test kit daily for qualitative analysis and the Garrett Gas Train for quantitative test analysis and then to treat accordingly with zinc or copper carbonate or with ironite sponge. Recent developments have produced a chelate zinc compound that is potentially more effective than the traditional materials and may be introduced. These materials react irreversibly with the sulphides. Whole mud analysis with the Garrett Gas Train will also measure the water insoluble sulphides, i.e. ZnS, FeS, and Fe2S3. This can provide useful information to help decide scavenger treatment levels. Hydrogen sulphide has the property of inverse solubility and so its solubility decreases as the temperature decreases giving rise to the chance of gaseous hydrogen sulphide, released as the mud cools in the pits. When sulphide problems are encountered steel embrittlement preventative treatments should be made. The toxicity should be the initial consideration for any treatment.

3/9/01

62

KDS Ltd.


When hydrogen sulphide gets into mud, the initial pH decrease should be corrected and maintained above 10 if possible. Large accumulations of the resulting sulphide ions should be eliminated by chemical means. Removal of the hydrogen sulphide or its resulting sulphide anion from a drilling mud requires its precipitation as an insoluble salt. Two acceptable methods involve the iron and zinc materials. The addition of zinc carbonate will form the insoluble zinc sulphide: S2- + ZnCO3 ---> ZnS + CO32Note that this technique may build up the concentration of soluble carbonates that may require subsequent calcium treatment to maintain mud properties. Excess zinc may also lead to loss of mud properties. A second method to precipitate sulphide involves the addition of Ironite sponge. 4 S2- + Fe3O4 + 4 H2O ---> Fe3S4 + 8 OHAn alternative technique uses copper salts to form insoluble copper sulphides. However this method should be avoided if at all possible. Any excess dissolved copper ions in solution will cause the iron in drill pipe to oxidize and corrode. This will cause the dissolved copper to plate out onto the drill pipe.

Zinc Carbonate The removal of hydrogen sulphide and sulphide anions from drilling fluids is facilitated by zinc carbonate. The sulphides are removed in the form of insoluble zinc sulphide. Zinc carbonate is non-corrosive to the ferrous metal surfaces and is effective in virtually all water based muds. It is effective in removing sulphides over a broad pH range, including alkaline environments. Zinc carbonate, added at 1 ppb, will treat out 500 ppm of hydrogen sulphide. When hydrogen sulphide is anticipated it is recommended that the mud system be pretreated with 2-3 ppb of zinc carbonate as large treatments with zinc carbonate may result in increased viscosity, addition of water and/or dispersant (Desco CF) is recommended to maintain fluid properties. The levels of hydrogen sulphide in the mud filtrate should be continually monitored with the Garrett Gas Train or Hach Paper Test while treatment continues. These tests will help prevent over treatment of the mud with zinc carbonate.

Corrosion Rings Corrosion has not been a problem with the salt concentrations high like they are. Corrosion decreases as chloride ion concentration increases from 3% to saturation. But most operators, from previous experience have run corrosion rings in the drill string starting at drill out from casing. The problem on most , is the time that a corrosion ring can actually stay in the string due to short sections. The coupons should be run for over 40 hours and pulled near 100 hours total time in the string. Conqor 404 is included as a contingency item.

3/9/01

63

KDS Ltd.


Contingency materials Definition Any material purposely added to the drilling fluid other than those included in the formulation for which the discharge permit applies. The drilling fluid systems are designed to function without the need for contingency materials during normal drilling fluid operations.

Conditions for use. If prevailing conditions, in a particular well, become or may become such that the drilling fluid become incompatible with safe and controllable drilling operations, addition of proper contingency materials may be required to modify the properties of the drilling fluid.

Cement Contamination Materials: Recommended concentrations. 1. Sodium Bicarbonate: 2. Citric Acid:

0.6ppb 0.6 ppb

Lost Circulation materials: 1. 2. 3. 4. 5.

Mica F/m: Nut Plug F/m /c: Kwikseal f/m Mix II F/M/c Calcium Carbonate

10 - 40 ppb 10 - 40 ppb 10 - 40 ppb 10 - 40 ppb 10 - 40 ppb

Stuck Pipe Materials: PIPE LAX (SEE FORMULATION CHART)

Hydrogen Sulphide Materials 1.

Zinc Carbonat 2 - 3 ppb

Corrosion 1. Conqor 4048 drms

Biocide Thinners Defoamer

3/9/01

64

DEEPWATER WELL PROGRAMME CONTINGENCY PRODUCTS

Barrels

Cu. Meters

Hole Size Starting Depth Final Depth Riser OD Riser ID Riser Length Casing #1 OD Casing #1 ID Casing # Length Casing #2 OD Casing #2 ID Casing # Length Casing #3 OD Casing #3 ID Casing # Length Solids Removal Efficiency Allowable Drill Solids Surface Volume Previous Casing Volume 61/2" Hole Volume Dilution volume

Product

Unit Size Mica fine / med 25 kg sks Nut plug fine /medium25 kg sks Kwikseal F / M 50 lb sks Cal. Carb F 25 kg sks Cal. Carb M 25 kg sks Mix 11 F 25 lb sks Mix 11 M 25 lb sks Conqor 404 55 gal drm Pipe Lax W 55 gal drm Finagreen 55 gal drm Glute 16 5 gal drm Soltex 50 lb sks Guar Gum 25 kg sks Defoam A 5 gal drm Tackle 5 gal drm Desco 25 lb sks Zinc Carbonate 25 kg sks

Total Estimated Volume

Table 10 Contingency Products

Author: Peter Aird

www.kingdomdrilling.co.uk

Ref:

Conc

Deep Water Drilling Fluid Design Example

Recommend Documents