SPE 151642 Design and Application of Drilling Fluids for HPHT Well - A Case Study of Mafia Field A.B.ORIJI, SPE and A.DOSUNMU, SPE: UNIVERSITY OF PORT-HARCOURT
Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the North Africa Technical Conference and Exhibition held in Cairo, Egypt, 20–22 February 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.
Abstract It is very important to design a stable mud system for any detailed drilling programs. Application of the best practices and well planned engineering field execution is critical in drilling and completing HPHT wells in a cost effective manner and minimal operational problems. Conventional mud designs and test equipment fell short of addressing the inherent problems associated with HPHT wells. In this study, the conventional practices in mud design were reviewed and advances in design for best practices developed for Mafia field. Many of the conventional practices were actually found to be inadequate for HPHT drilling. This paper present techniques on determining and applying mud properties at HPHT deep wells through a rigorous laboratory test and mathematical equations to generate detailed engineering guidelines for HPHT drilling fluids .Water based mud were formulated with special additives at temperature between 250-500oF and 5,000-10,000 psi to check for its stability under such elevated temperature and pressure. A standard temperature concept used for controlling the surface mud weight was defined. With the actual field results from the Mafia field, model equations were developed and the sensitivity analysis done to show the relative influence of pressure and temperature on the drilling fluids using the spider and tornado plots . The model equations derived from the multiple regression analysis were used to predict and rank the best rheological properties for the field , thereby saving the time and rigors associated with laboratory experiments. Introduction Over the years, the drilling for oil and gas is a high risk and challenging venture. Despite the uncertainly and the problem associated with the drilling operations, HPHT wells are being drilled everyday. In order to overcome these problems, the drilling engineers must prepare for these challenges so as to meet the expected revenue and the time allocated for a particular drilling job. Drilling fluids are usually formulated to meet certain properties to enable it carry out the basic functions. HPHT are by far the most prevalent problem affecting the drilling fluids by destroying the mud properties and slowing down the drilling rate. To optimize the drilling mud performance, we then need to understand the nature , the geology of the formation and the basic functions of the drilling mud .Most formations are at very high temperature and pressure at a considerable high depth into the earth. Hence there is the need for a proper balance of this temperature and pressure to avoid oil and gas surge, kicks, formation damage and other drilling hazards associated to HPHT in geothermal oil and gas well. Many of the conventional chemical additives for drilling fluids are quite unsuitable for use at very high temperature and pressure, therefore, advances and modifications of formulation or the development of entire new drilling-fluid materials is a matter of continuous research. The choice of any drilling fluid used in HPHT well construction has a critical influence on the extent to which an operator can meet his objectives because the fluid performance will play a significant part in determining whether key performance indicator targets like well control, safety incidents, well integrity and productivity index are met22. Very high Bottom hole temperature and pressure actually degrades the rheological properties of conventional mud causing both dynamic and static Barite sag thereby increasing the risk of loss of well control more particularly in high angle wells. However, drilling for oil and gas in HPHT area is now one of the greatest technological breakthrough in recent decades, and many new techniques have been developed to profit from the abundance of oil and gas from this harsh environment. The demand for oil and gas is increasing by the day, and to meet this demand, oil and gas need to be discovered in environments new to the petroleum industry. To do this, technologies used in conventional terrains have been modified to adapt to this
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difficult environments. For HPHT wells, it is evidence by the new set of drilling fluids and its applications. Oil and gas production wells are now drilled more or less routinely in HPHT fields even though drilling is often more difficult, expensive, and dangerous than for an oil and gas well of equal depth in a normal temperature and pressure wells. Therefore, successful drilling of HPHT wells critically depends on the drilling fluids engineering designs and applications for specific down hole conditions. Background Information The first deep test well to be drilled in East Africa was located on Mafia Island off the Tanganyika coast. The Island is approximately 30 miles long in south-south-west and north –north- east direction. It lies approximately 15 miles from the mainland at the mouth of the Rufiji River. Mafia well 1.(MAF-1), being the first stratigraphic test well in East Africa was placed as far out as possible into the basin of Mesozoic and Tertiary sedimentation of the Indian Ocean in order to obtain the most complete record possible of this formation. This, together with the knowledge that such beds are more fully developed in the southern part of the coastal belt of Tanganyika, led to the consideration of Mafia island as a possible site for the well. In order to combine the stratigraphic test with an investigation of the oil potentials of the area, some positive structure which might act as a trap for oil accumulations in the island consisted of solid rocks of active reef formation and which lies close to the extensive Mafiji delta. It was then thought that the island might represent a positive structural element in the middle of an actively subsiding continental shelf. On these grounds, detailed geological and geophysical surveys of the island were undertaken and the presence of a positive structure established beyond doubt. Mafia island was found to be mostly covered by a thick blanket of loose sand and the majority of the surface rocks were discovered to consist of lower Miocene Limestones. Mafia well-1 was then drilled in 1955 as a stratigraphic and exploration combination. The main objective was to investigate the stratigraphic column in the Mesozoic and tertiary formations and then examine the petroleum production potentialities of any reservoir bed especially from the main seismic high velocity medium. Though the drill string became irretrievably stuck at 3368 metres in 1956 and the well was abandoned . The only suggestion of a structure prior to drilling was the presence of raised lower Miocene at the surface and a confirmed high gravity over the central area of the island. The well was bottomed in Campanian age sandstones and shales overlying undated volcanic rocks. Being extrusive and interbedded with shales and sandstones. These volcanic were and are still considered to be of the same age as the sediments. During this period only minor shows were recorded, although the numerous lost circulation zones with the resultant influx of drill water, made any observation of shows questionable. In the recent year, 3-D,seismic prognosis showed that Mafia field has temperature and pressure up to 500 deg. F(BHST), and above 10,000 psi (BHSP) respectively. The exploration well Mafia deep well-1.(MAFD-1) was then planned to be drilled vertically at a total depth of 5000 metres with the objective of evaluating the clastic reservoirs of the lower cretaceous lying below a thick, regional Upper Cretaceous sealing shale interval. The sandstones were prognosed to be of excellent quality with porosities ranging from 10 to 21 percent although some degradation was likely due to the greater depth of burial. This led to an investigation and development of HPHT drilling fluids through experimental procedures, simulation studies , field application and execution project . During drilling of Mafia deep well -1.(MAFD 1), the well was monitored daily for over one year involving fluid pilot testing, fluid maintenance and designing/redesigning fluid programs according to well conditions to generate enough drilling fluids field data to serve as offset well information for the developing and drilling of future wells in Mafia field. . HPHT Definitions and Classifications HPHT well has been defined by United Kingdom Continental Shelf Operations Notice, as any well where the undisturbed bottom hole temperature is above 300 deg. F and the pore pressure gradient exceeds 0.80 psi/ft . HPHT wells are classified into three tiers . The first tier of HPHT wells refer to wells with reservoir pressures greater 10,000 psi to 15,00psi (689 bar to1,034 bar), with temperature between 300 to 350 deg. F. Most HPHT operations to date have taken place under tier one conditions. Tiers two are the “Extreme HPHT’’ wells, which are characterized by reservoir pressures greater than 15,000 psi to 20,000psi and with temperatures up to 400 deg. F. Many upcoming HPHT deepwater gas/oil wells fall into the tier two category. Tier three encompasses “Ultra HPHT’ wells, with reservoir pressures greater than 20,000psi to 30,000 psi and with temperature up to 500 deg. F. Tier three is the HPHT segment with the most significant technology gaps and several deep gas reservoirs fall under this category leading to major changes in design criteria and operational procedures. The resulting requirements may range from simple upgrade of existing designs to complete re-design with new materials, additional analysis and geometries. HPHT wells are considered critical because of the more severe well conditions like borehole instability, fractured formation and excessive lost circulation. Therefore, several design processes are needed and considered to ensure construction of HPHT wells to a desired depth in a safe and economic manner. Hence, some of the most important stages definitely involved good drilling fluid designs, applications and proper management. HPHT Challenges Although a number of HPHT wells have been drilled in different part of the world, these wells still present a drilling challenge because technologies to effectively monitor down-hole pressures and temperatures are not well developed. Some
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of the major challenges includes: • A common problem in HPHT well is poorly cemented sands forming a highly unconsolidated formation that can lead to excessive loss circulation of the drilling fluids. • Shale problems are more felt in HPHT wells and can easily lead to pipe sticking and poor hole cleaning causing major well control issues. • HPHT can cause abnormal physical and chemical reactions of the active clays of the mud resulting to thermal degradation and flocculation . • High density fluid is required, translating to high solids loading that could cause barite sagging leading to high frictional pressure losses . • HPHT wells depend greatly upon the in-situ tectonic stresses and the formation pressure that can cause borehole instability. • Considerable amount of time and cost is spent while drilling HPHT wells, particularly setting the production casing and testing the reservoir leading to very small operating margins. • Actual knowledge of formation pressure, preventing a kick or circulation losses is very difficult particularly in a fractured formations and in a highly unconsolidated formation. • Harsh conditions like Hydrogen sulfide(H2S), corrosive and erosive, complex, risky and prone to failure. • HPHT will shorten bit life and performance thereby increasing overall well engineering cost • HPHT wells require special drilling fluids, special cement slurry and special high performance equipment. Conventional HPHT Drilling Fluids Design Conventional drilling fluids have inherent limitations in HPHT drilling conditions. High loading of barite in conventional mud creates high frictional pressure losses during circulation in long sections, leading to unacceptably high equivalent circulating densities in narrow drilling windows . In conventional mud, HPHT can break down the solids-carrying capacity ( yield point) causing both dynamic and static barite sag and severely increasing the risk of loss of well control particularly in high-angle wells. Conventional Invert emulsion fluids have been designed and utilized for drilling HPHT wells, but it can also absorb large volumes of gas and this can cause well control problems if the mud remains static for long periods of time22. To make things worse for the conventional design, an influx of hydrocarbon gas into a designed oil-based mud may destabilize the formulation and cause rheological problems. However, It is more common occurrence to have hole washouts while drilling with conventional water-based mud than for invert emulsion in HPHT wells. Hole washout can lead to poor hole cleaning , increased chances of stuck pipe, poor wire-line log and bad zonal isolation17. Also, laboratory return permeability tests done on some samples of conventional water based mud showed that they can cause considerable formation damage and that the presence of very high levels of barite in high-weight mud formulated for HPHT wells did not improve such situation. Conventionally, plastic viscosity and yield point were used to define the specification of mud performance during design and application. These two parameters were used to “optimize” mud formulations with the aim of achieving as low plastic viscosity as possible. This worked well in most wells due to the large tolerable errors. However, for HPHT wells, this has significantly increased the drilling problems such as lost circulation, surging/swabbing and kicks. The perception in the industry was that the higher the plastic viscosity, the higher the equivalent circulating density, therefore efforts were made during design and application to minimize the plastic viscosity in the optimization of mud engineering. Fennell and Gao argued that the plastic viscosity and yield point were not very relevant to the equivalent circulating density as they were only derived from the 600-rpm and 300-rpm readings of the Fann viscometer and therefore demonstrated that mud with a lower plastic viscosity can also result in a higher equivalent circulating density than mud with a higher plastic viscosity particularly in HPHT wells12. Traditionally, during design and application most engineers measure the mud temperature directly from the flowline and surface mud weight were not correlated against the temperature and were always assumed constant no matter the mud temperature. The procedure led to significant errors of 5-15 deg.F different from the mud temperature inside the mud balance for HPHT fluids at the time of measuring the mud weight thereby leading to errors in the actual mud weight. This could be risky but can be prevented by measuring the surface mud weight so that it can be correlated with temperature as will be discussed in the advances in the drilling fluids design for HPHT wells. Advances in HPHT Drilling Fluids Design Literatures showed that for non-HPHT wells, the effects of pressure and temperature on mud weight and rheology is minimal and can be ignored. However, for HPHT wells the effects of pressure and temperature on rheology, surface mud weight, the equivalent down-hole mud weight and the equivalent circulating density must be taken into consideration .Early investigation into the effects of temperature on the rheological properties of drilling fluids were performed by Bartlett in 1967 and the study showed significant decrease in mud properties of a particular lignosulfonate mud when its temperature was increased from 80OF to 140OF . Alderman et al1 made measurements on the rheology of several water-based drilling fluids at
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temperature up to 266OF and pressure up to 14,500 psig. Their data were then used for a three-parameter Herschel-Bulkley model and power –law model. In both models, it was observed that the behavior of the high-shear viscosity reflected the viscous nature of the continuous phase showing a weak pressure dependence and exponential temperature dependence similar to that of water. With the depth horizons of HPHT wells, a technology gap was recognized in the measurement of fluid properties at down-hole conditions. Ron et al23 designed and fabricated a new viscometer, the chandler 7600 suitable for HPHT fluids rheological measurement up to Working pressure of 40,000 psig and Working temperature up to 600°F. For the Mafia field, the laboratory experiment were based on factorial design concepts were series of test were performed using the chandler model 7600 ultra-High pressure and High temperature viscometer to evaluate the performance of the drilling fluids relative to its rheological behaviors. The Chandler model 7600 Ultra-High Pressure High Temperature viscometer is an automated concentric cylinder viscometer that uses a rotor and bob geometry. All the test were conducted in line with standard ISO and API procedures for rheology measurement at high temperature and high pressure . Due to the inaccuracy in the traditional way of measuring flowline temperature and mud weight, a new procedure was developed and implemented for the HPHT well in Mafia field, the advanced procedures included the following steps: • Take a sample from the flowline or active pit • Measure the viscosity (Marsh Funnel) • Flush the mud balance twice with the mud sample • Fill up the mud balance • Measure the mud temperature inside the mud balance • Measure the mud weight • Record the temperature and mud weight • Measure and record the flowline temperature With the above procedures, the flowline temperature and the mud temperature at which the surface mud weight is measured are different under HPHT conditions. The flowline temperatures were used to correlate and calculate the equivalent mud weight and the temperature at which the flowline mud weight was measured were used as a baseline for surface mud weight control. It was noted that maintaining a constant surface mud weight under HPHT conditions was very difficult as the mud weight tends to increase due to water evaporation and accumulation of fine drill solids.. The surface mud weight versus temperature chart was updated on a regular basis to correct for any changes which reduced well control issues to a minimal level while drilling the Mafia deep well-1. These procedures were proved to be successful throughout the drilling of Mafia deep well -1 to the expected target at 5600 metres. Application A number of rheological models , based on mathematical equations relating shear stress and shear rate conditions have been previously developed in order to predict fluids behavior . However most drilling fluids are too complex to allow a single set of equations to be used in determining their behavior under all conditions. Therefore the utilization of the appropriate rheological model together with shear stress and shear rate data obtained from a suitable instrument allows accurate determination of the fluid behavior under varying flow conditions found in the oilfield. The data obtained formed the basis for further calculations used to determine several important aspects related to the drilling fluid’s performance. For the Mafia field a software called HPHT Rheo-Analyzer was developed using a multiple regression analysis for a two factor factorial to investigated the relationship between the effect of high pressure and high temperature on mafia drilling fluid properties. Actual field data were assembled and regressed to estimate the quantitative effect of temperature and pressure. The statistical significant of the estimated relationship provided the degree of confidence ,that is if the true relationship was close to the estimated relationship. The mathematical model equations(1-4) described the relationship between the dependent variables, the mud properties(PV,YP,GS,AV) and the independent variables(temperature and pressure: P/T). : A,B,C and D are the coefficients, PV=plastic viscosity, YP =yield point, GS = gel strength, AV= apparent viscosity. ----------------------------------1 PV = A0 - A1P-0.5 + A2T-4 - A3 P2 T-3 -p/1000 -T/1000 2 -3 ----------------------------2 YP = -B0 +B1e + B2e +B3 P T -------------------------------3 GS= -C0 + C1P-0.5 + C2T-6 - C3 P-2 T-3 2 -3 --------------------------4 AV= D0 + D1 Log P + D2 Log T + D3 P T
Discussion Factorial design is one of the most efficient ways of investigating experiments that involved the study of the effects of two or more factors. It allowed the effects of temperature to be estimated at several changes of pressure and verse versa ,which gave valid results over a range of experimental conditions especially with the interaction effect of temperature and pressure. Temperature and pressure were the two factors investigated in order to develop a methodology for testing HPHT drilling fluids using the automated Chandler model 7600 ultra-HPHT viscometer. The test were conducted at temperatures between(
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250-5000F) and pressures between(5000-10000psi) . Results were obtained at 600rpm, 300rpm, 200rpm, 100rpm, 6rpm and 3 rpm respectively. All the equipments used during the laboratory design were according to API specification for equipments and testing procedures. The test results indicated that pressure and temperature can independently affect rheological parameters as well as its interaction effects as shown in the sensitivity analysis plots thereby confirming the trend obtained from the model results. Numerical results calculated from the model equations showed good agreement with experimental values with less than 1% error. This helped to predict rheological parameters at different temperatures and pressures thereby saving time and rigors associated with laboratory test. Also, the advances made in the modeling led to a better understanding and the development of techniques in determining effective mud rheology which is critical for the analysis of drilling and completion fluids. Conclusion Recent developments and advances have contributed to the successful drilling of HPHT wells in Mafia field with a stable mud system, best practices and correct field execution .The following main conclusions about drilling fluids engineering and management in HPHT wells can now be drawn. • Rigorous laboratory testing is necessary to generate detailed engineering guidelines for HPHT drilling fluids. HPHT mud are very sensitive to treatments, therefore, pilot tests must be carried out before adding any chemical into the active circulating system to ensure that any depletion of additives is compensated for. • A new viscometer has been designed which has met a higher design criteria for HPHT fluid testing up to 40,000 psig and 600°F. • Once the minimum overbalance is determined for HPHT well, the standard temperature for surface mud weight was defined. Thereafter the mud weight was maintained within a matrix which references the standard weight at the standard temperature. • The mud balance was properly calibrated using the new established method and mud temperatures were reported with any mud weight measurement because HPHT drilling cannot afford much errors in intended mud weight due to wrong measurements. • The rig crews were briefed on procedures that differ from previously accepted practices and their roles during well control issues. The was continuity of rig key personnel throughout the drilling operations. • Due to the reduced hydrostatic overbalance in the HPHT well, particular care was exercised immediately after stopping any circulation and the well flow checked as much as possible. • A careful investigation on the rheological properties of the water based fluid at simulated HPHT was very important and was carried out for precise hydraulic programs in order to calculate the pressure drop in the annulus, predicting equivalent circulating density as well as controlling the bottom hole pressure. Recommendation • • •
It is recommended to combine drilling logs, offset well data, seismic data and drilling technologies driven by a proper understanding of the HPHT effect on drilling fluids, so that future wells will be successfully drilled to targets in terms of cost savings and minimizing time overruns on such drilling projects. It is necessary that there should be a close collaboration between drilling fluid Engineers and Well Engineering team during the period of design, planning, implementation and construction of HPHT geothermal wells to enable them understand the basis and background of the project. It is possible to drill HPHT wells with narrow mud weight window safely with minimal well control incidents, if proper mud design , training of rig crew and continuity of key personnel are adhered to.
Acknowledgment The Authors are greatly indebted to the Drilling Fluids Research Program at the Department of petroleum and Gas Engineering of the university of Port-Harcourt . Special thanks to Mario Bertnori and Lauran Kokkinos of Maurel and Prom for been of great assistance while I was working as a Drilling Fluids Specialist on the MAFIA FIELD. References 1. 2. 3. 4.
Alderman, N.J, Gavignet, A, Guillot D, and Maitland G.C.(1988): ‘’High-Temperature, High-Pressure Rheology of Water-Based Muds” SPE 18035.Annual Technical Conference and Exhibition, Houston, Texas. Azar, J.J. and Robello, S. G. “Drilling Engineering”, PennWell Corporation, Okhlahoma, USA, 2007. Baroid Drilling Fluids Inc., “Manual of Drilling Fluids Technology”, Copyright Houston, Texas, 1990. Bartlett, L.E(1967). : “Effects of Temperature on the Flow Properties of Drilling Fluids,”paper SPE 1861 .Annual Meeting of AIME, Houston Texas.
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5. 6. 7.
8. 9.
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11.
12.
13.
14. 15. 16. 17.
18.
19. 20. 21. 22. 23.
Broughton G and Hand R. S. (1938) “Viscosity Characteristics of Clays in connection with drilling mud”, Transaction AIME (1938) 1002, 69. Chandler(2007):HPHTViscometer,ChandlerEngineering,Ametek:http://www.Chandlereng.com/products/drillingflui ds. Davison, J.M., Clary, S., Saasen, A., Allouche, M., Bodin, D., Nguyen, V.A.(1999): “Rheology of Various Drilling Fluid System Under Deepwater Drilling Conditions and the Importance of Accurate Predictions of Downhole Fluid Hydraulics”, SPE 56632, Houston Elliott. G. S., Brockman. R.A. and Shivers III. R. M., “HPHT Drilling and Completion Design for the Erskine Field”, SPE 00030364, presented at Offshore Europe 95, Aberdeen, Scotland, 5-8 September 1995. Erhu, G. et al.: “Critical Requirements for Successful Fluid Engineering in HPHT Wells: Modeling Tools, Design Procedures & Bottom Hole Pressure Management in the Field”, SPE 50581 presented at the 1998 SPE European Petroleum Conference, The Hague, The Netherlands, 20-22 October 1998. Erhu, G. et al: “Continued Improvements on High-Pressure/High-Temperature Drilling Performance on Wells with Extremely Narrow Drilling Windows – Experiences from Mud Formulation to Operational Practices, Shearwater Project”, SPE 59175 presented at the SPE Drilling Conference held in New Orleans, Louisiana, 23-25 February 2000. Fambon. L., Joffroy. G., “Successful Development Drilling of an HP/HT Infill Well in a Highly Depleted Reservoir: Case Study”, SPE 112708, presented at the 2008 IADC/SPE Drilling Conference, Orlando, Florida, USA, 4-6 March 2008. Fennell, B. and Gao, E.: “Examining the Practical Aspects of Drilling a Horizontal HP/HT Well,” paper presented at the Latest Advances in Safe and Cost Effective HP/HT Drilling, Completion and Intervention, Aberdeen 19th & 20th November 1998. Gao, E., Estensen, O., MacDonald, C. and Castle, S.: “Critical Requirements for Successful Fluid Engineering in HPHT Wells: Modelling Tools, Design Procedures & Bottom Hole Pressure Management in the Field,” paper SPE 50581 presented at the 1998 SPE European Petroleum Conference, The Hague, The Netherlands, 20-22 October 1998. Ibeh C. S (2007): Investigation on the effects of ultra-high pressure and temperature on the rheological properties of oil-based drilling fluids. Texas A&M University Michael R.M (2007) : Decision Analysis using Microsoft Excel. School of Business and Management. University of San Francisco Montgomery, D.C.(1991): ‘’Design and Analysis of Experiments, third edition, John Wiley & Sons, New York City. Osama, B., Ahmed, K.: “Custom Designed Water-Based-Mud System Helped Minimize Hole Washouts in HighTemperature Wells: Case History From Western Desert, Egypt” SPE/IADC 108292, presented at the SPE/IADC Middle East Drilling Technology Conference and Exhibition, Cairo, Egypt, 22-24 October 2007. Owolabi, O.O, Oriji, A.B, and Ajienka J.A. (1991): “Effects of Temperature and Salt on the Rheological properties of Kaolinitic Drilling Mud Clays”. Referred proceeding, Paper SPEN 9102, 15th Annual International conferences of the SPE, Nigerian council, August Port Harcourt, Nigeria Peters, E.J., Chenevert, M.E. and Zhang, C.(1990): “A Model for Predicting the Density of Oil-Based Muds at High Pressures and Temperatures”, SPEDE Trans., AIME,289. Romero, J. and Touboul, E.,(1998): “Temperature Prediction for Deepwater Wells: A Field Validation Methodology,” SPE 49056, New Orleans Rommetveit, R., Bjorkevoll, K.S.,(1997): “Temperature and Pressure Effects on Drilling Fluid Rheology and ECD in Very Deep Wells”, SPE 39282, Bahrain. Rommetveit, R., Fjelde, K.K., Aas, B., Day, N.M., Low, E. and Schwartz, H.: “HPHT Well Control; an Integrated Approach,” OTC 15322, Offshore Technology Conference, Houston, May 5-8, 2003. Ron, B. et al.: “HP/HT Drilling Fluids Challenges” IADC/SPE 103731, presented at the IADC/SPE Asia Pacific Drilling Technology Conference, Bangkok, Thailand, 13-15 November 2006.
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Appendix
Table 1: Laboratory formulation of HPHT Polymer system at different temperature Test temperature: (oF) 250 300 350 400 450 CHEMICAL ADDITIVE : (Kg/m3) Save scav HS 2 2 2 2 2 Driscal D 10 10 10 10 10 Sepiolite 30 30 30 30 30 Thermatin 6 6 6 6 6 Safe Carb 10 100 100 100 100 100 EMI-1048 2 2 2 2 2 Dristemp 8 8 8 8 8
500 2 10 30 6 100 2 8
Table 2: Laboratory results of HPHT Polymer system at different temperature 250 300 350 400 Temperature: (oF) 2 23 16 34 27 Plastic viscosity(Ibs/100ft ) 35 39 24 20 Yield Point (Ibs/100 ft2) 22 41 45 60 Gel strength, (10mins)
450 28 21 62
500 35 21 72
Gel strength , (10sec)
10
30
31
35
40
41
Apparent viscosity(cp) API fluid loss(ml) HPHT fluid loss (ml) Density(sg)
32 6.5 12 1.17
125 7 15 1.14
160 5.8 23 1.21
152 6.1 21 1.26
133 7.4 23 1.22
146 7.1 22 1.31
Table 3: Summary of the actual field concentration and products function Chemical Additives Concentration. Kg/m3 Save scav HS 1-2 Bentonite 25-30 Thermatin 3-6 Sepiolite 25-30 Safe Carb 10 60-100 EMI-1048 1.5-2.0 Dristemp 6-8 Driscal D 8-10
Function H2S Scavenger Secondary Viscosifier HPHT Fluid loss control Extreme HTHP gel Weighting agent HPHT thinner HPHT Viscosifier HPHT Fluid loss control
Table 4. Summary of the actual HPHT drilling fluids field results Measurem MW MF YP FL pH PV ents. V
% solid
% sand
Gel0 (10sec)
Gel0 (10im )
HPHT FL.
Result
12-14
0.250.50
3 -15
5-25
5-20
1.121.31
60100
2050
3 -6
8 -10
25-35
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Strati.
Z
Environ.
g Litho
Depth MD
Drilling phases & Casings
TVDSS
Miocene
32 m
m
635 m 700 m
m m
Reservoirs Mud losses
Conducteur pipe 42’’ beaten at 30 m Drilling in 26’’ then enlarged in 36’’ Casing 30’’ seat at 190 m
Back reef
Oligocene
Drilling in 26’’
Reef Fore reef
1000 m
Casing 20’’ seat at 1200 m Inner-mid shelf
Eocene
Drilling in 17 1/2’’
2000 m cavings 2150 m
m
Paleocene
Casing 13 3/8’’ seat at 2500 m
Outer shelf
3000 m
2775 m
m
Drilling in 12 1/4’’
Casing 9 5/8’’ seat at 3800 m Lowstand
Upper Cretaceous 4000 m
Drilling in 8 1/2’’
4500 m
Deltaic
Lower Cretaceous
5000 m
m
Casing 7’’ seat at TD in case of discovery (5000 m maxi)
Figure 1:Lithology prognosis of Mafia deep well -1
Figure 2: Plots of the HPHT fluid rheology and temperature at field conditions
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Figure 3: Sensitivity plot of the effects of high pressure and high temperature on apparent viscosity(AV)
Figure 4: Sensitivity plot of the effects of high pressure and high temperature on plastic viscosity(PV)
Figure 5: Sensitivity plot of the effects of high pressure and high temperature on yield point(YP)
Figure 6: Sensitivity plot of the effects of high pressure and high temperature on Gel Strength(GS)
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