SPE 84552 Estimating Fracture Gradient in Gulf of Mexico Deepwater, Shallow, Massive Salt Sections J.W. Barker, SPE, and W.R. Meeks, SPE, ExxonMobil Development Company
Copyright 2003, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in Denver, Colorado, U.S.A., 5-8 October 2003. This paper was selected for presentation by an SPE/IADC Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted restricted to an abstract of not more than 300 words; words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of of where and by whom the paper was was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.
Abstract Drilling massive salt sections in the deepwater Gulf of Mexico is becoming becoming a frequent occurrence. The abundance of salt and the ability of seismic to image under salt have made drilling massive massive salt sections common place. place. It is estimated estimated that over a hundred wells in the deepwater Gulf of Mexico have penetrated salt at both shallow and deeper well depths. As the industry gains experience drilling deepwater, shallow allochthonous salt bodies, several advantages of drilling through, rather than around, salt have emerged. emerged. Fracture gradients in shallow salt intervals have proven to be much higher than in non-salt sediments at a comparable depth. As a result of the increased fracture pressure, massive salt sections have been used to extend casing points and eliminate casing strings, resulting in greatly reduced well costs through reduced rig time, well tangibles, underreaming, cement volumes, and mud volumes. volumes. Many operators are now choosing to drill massive, shallow salt sections to take advantage of these benefits. In some cases these cost savings have the potential of making marginal deepwater reserves economically feasible to develop and produce. A reliable reliable estimate estimate of the fracture gradient in shallow, massive salt sections is needed to design casing strings and plan mud weights for safe and cost effective wells. Upon exiting a shallow salt zone, often the formation pore pressure and fracture pressure are very close. Typically this condition results in drilling problems including lost returns, well control events, events, etc. The proper choice of a mud weight to exit a shallow, massive salt section can be a critical factor for both well integrity integrity and cost. This paper describes a method to estimate the fracture gradient for a salt formation formation below a casing shoe. The method is based on experience gained while drilling wells which penetrated substantial salt sections. Also presented are
guidelines that can help in selecting a mud weight when exiting the bottom of a massive shallow salt section.
Introduction The U.S. gulf coast basin contains the largest known deposits of salt in the world. It has been estimated that that 80 percent of the proven gulf basin reserves are likely related to salt structures. 1 Drilling through massive salt sections has been achieved along the gulf coast since the 1940s and is common place on land, on the Gulf of Mexico (GOM) shelf, and in the Gulf of Mexico deepwater today. In the mid 1980s the industry began to drill in the deepwater Gulf of Mexico. Mexico. Salt walls, walls, diapers, and allochthonous salt bodies are common in the deeper water depths of the GOM as 2 shown in Fig. 1. In many cases shallow salt sheets cover entire GOM block areas. In the early 1990s deepwater GOM shallow salt sheets began to be drilled in order to reach reach deeper geologic objectives. New seismic acquisition techniques and depth migration processing advancements resulted in improved imaging of subsalt clastic formations. In 1990 Exxon Exxon spudded the Mississippi Canyon Block 211 No. 1 well in 4,352 ft of water depth with the objective of exploring exploring subsalt formations. formations. The well was the industry’s first find of significant subsalt, deepwater hydrocarbons. An apprasial well was drilled drilled in 1997 and the discovery was subsequently developed with three subsea completions. In 1995 Texaco Texaco discovered a subsalt field at Mississippi Canyon Block 292 in 3,400 ft of water and developed this field with three wells in 1999. 3 Today operators routinely drill shallow salt layers to explore and produce deeper objectives. Drilling shallow salt intervals has become a preferred option because two issues have been overcome in recent years. First, studies have concluded that that salt loading on well casings due to salt creep is manageable for salt formations encountered along the US gulf coast. 4 Second, operational problems experienced while drilling salt sections in early wells have been o vercome. Shallow GOM salt is typically very hard which leads to low drilling penetration rates, directional control control problems, and excessive vibrations. Early experience with drilling shallow salt zones resulted in average penetration rates in salt of only 10 to 20 ft/hr. New tools and operational practices have permitted drilling salt today at over 50 ft/hr with minimal directional problems and drillstring vibrations.5,6
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Many operators have observed that the achievable fracture pressure in a deepwater, shallow salt interval is higher than would be expected in a comparable non-salt formation. In many cases the fracture gradient of salt below a casing string was observed to be significantly above overburden. In order for the well designer to assess the benefit of drilling shallow salt zones and choose an optimum well site, a method of estimating the fracture gradient in the salt must be known. With this information estimating subsequent casing depths can be better assessed and the benefit of drilling shallow salt zones can be adequately evaluated. Also vital to a well planner is an estimate of the mud weight that will be required when exiting a massive salt layer. Knowing this will permit the choosing of an optimum location to exit the salt and will lead to an understanding of how much drilling can be achieved before setting the next subsequent casing string.
Geologic Setting The GOM basin was formed in the late Middle to early Upper Jurassic as North America separated from South America and Africa.7 After the basin had formed, evaporate salt (Louann) was deposited over thousands of years. This salt underlies most of the present day gulf coast basin except for some localized areas. During Cenozoic and earlier geologic time, the gulf coast basin partially filled with sediments and was molded into a structurally complex region by growth faults, diaperism, and salt flow. Near the gulf coast land and shelf margin, the Louann can be 30,000 to 40,000 ft deep (Fig. 2). In deeper GOM water depths, the Louann is shallower and more often encountered when drilling wells. The reduction in sediment overburden in deep water is thought to permit massive amounts of salt to move vertically more easily. Typically, salt does not change in density with burial depth as do most clastic sediments. Shallow GOM deepwater formations are very young geologically, often have a very high water content, and have fairly low bulk density. Most clastic sediments increase in density rapidly with burial depth and overburden. Many believe that the shallow salt sheet features often seen in the deepwater GOM are a result of the salt moving upward until the density of the salt equals the density of the sediments. The salt in essence “floats” or is in equilibrium with the soil just above and just below it. After the salt reaches equilibrium, it often moves horizontally and can actually detach from its parent salt (allochthonous). These salt sheets can cover many square miles and often collide and impact other salt sheets. A area of mixed salt and sand/shale formation may exist in this zone which many refer to as a suture.
Behavior of Salt as an Engineering Material Often formations are categorized as “brittle” or “plastic” (see Fig. 3). The term brittle is typically used to describe hard rock and plastic or ductile is used loosely to describe soft rock. Many geologic materials exhibit a brittle stress-strain curve, which is basically linear, until failure is approached. Salt is a unique engineering material and its behavior under stress is much different that other materials such as rocks or metals.
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Ductile or plastic materials, such as salt and very unconsolidated shales, have a limited linear stress-strain curve at very low stresses only. These materials typically fail plastically rather than in brittle elastic failures. At stress levels that can be as low as 10 to 20 percent of its ultimate strength, salt can begin to deform plastically. The stress-strain curve for salt is very dependent on temperature, confining pressures, salt composition, water content, impurities, prior stress history, loading rate, and other factors. Salt can be described as a viscoelastic-viscoplastic material due to the different ways it can behave since its strength is so dependent on these variables. The tensile strength of rock will vary from zero for unconsolidated materials to perhaps several hundred psi for the strongest rocks. In the real world the tensile strength for most formations drilled is effectively zero due to joints, bedding, and laminations. Salt formations typically have a tensile strength of only a few hundred psi. Limited data indicates the uniaxial compressive strength of salt can range from about 1,800 to 3,000 psi. Poisson’s ratio is the ratio of horizontal to vertical strain. Poisson’s ratio has been observed to vary from values ranging from 0.25 to 0.5 for salt. 4,8 Typically lower stress levels result in a higher Poisson’s ratio in salt. The salt encountered along the GOM gulf coast is generally very pure, as high as 94 to 97 percent halite. The pure mineral halite has a density of 2.17 g/cm3; however, in-situ salt density usually averages about 2.0 to 2.1 g/cm 3 in the deepwater GOM.9
Fracture Gradient – Historical Perspective The general equation used by most prediction techniques is 10
fracture
Total horizontal stress = K x Total vertical stress.............…(1) where K is the total horizontal to total vertical stress ratio. Over twenty different models have been developed by industry to estimate the horizontal to vertical stress ratio. These models assume the stress ratio is a function of many variables including formation density, Poisson’s ratio, compaction, depth, and other factors. For hard brittle rocks that behave elastically, the value of the stress ratio is typically in the range of 0.3 to 0.5. For soft materials that behave plastically, such as shallow shales, the stress ratio can be much higher and can approach 0.8 to 1.0. 10,11,12 Some have concluded that soft soil near the seabed behaves in a similar manner as deeper rock and that the fracture pressure of soft soils is basically stress dominated. 13 In 1923 Terzaghi introduced the concept of effective stress. This concept concluded that the total stress in a rock is composed of two stresses. The stresses are the pore pressure and an additional stress in the matrix of the solid part of the rock, effective stress. This can be written as Total Stress =Pore Pressure + Effective Stress..…………….(2)
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Since the fluid in the pore spaces pressure is equal in all directions, it is sometimes referred to as a neutral stress. Rearranging Eq. 2 results in the following equation: Effective Stress = Total Stress – Pore Pressure…….……….(3) In a wellbore drilled in typical clastic formations, the total stress (vertical) is very nearly equal to the weight of the overlying material, i.e., the overburden pressure. If pore pressure were at its extreme, where the pore pressure was equal to the overburden pressure, the effective vertical stress would be equal to zero. This is often called a low effective stress condition. In terms of effective stress, Eq. 1 can be written as Fracture pressure = K x (Overburden pressure – Pore pressure) + Pore pressure…………………..……………………….....(4) When the stress ratio is near unity, the sensitivity of pore pressure on fracture pressure is small and fracture pressure is primarily dependent on overburden. A shallow below mudline (bml) fracture gradient curve for shallow formations in the southern Mississippi Canyon area of the GOM is shown in Fig. 4. This curve was developed from offset wells in the area and is based on an 85 ft airgap and a 4,275 ft water depth. This curve includes adjustment of the offset wells for water depth and airgap of the rig. Ref. 11 outlines the methodology used to calculate this fracture gradient curve. For shallow non-salt formations in the southern Mississippi Canyon area, this curve has proven to result in fairly accurate fracture pressure predictions. Note that estimates of overburden and pore pressure are not required to estimate fracture gradient with this method.
Fracture Pressure in Salt There are many references in the literature that cite examples of the stress ratio in salt formations exceeding two. 8 The unexpectedly high horizontal stress states have been attributed to several factors including residual stresses from prior tectonic activity and ductility of the formation. The current day stress in a formation is a very complex interaction of rock properties, tectonics, burial history, and temperatures. By adding a term that combines the unknown horizontal tectonic stress, tensile strength of salt, and other unknown stresses, then Eq. 1 can be written as Total horizontal stress = K x Total vertical stress + Additional non-gravitional stresses........................................................(5) If the stress ratio is unity for shallow, deepwater plastic formations as suggested by several authors, then using Eq. 5 and expressing it in terms of effective stress, Eq. 1 reduces to Fracture pressure = Overburden pressure + Additional nongravitional stresses……....................................................…(6) If the fracture pressure and overburden in a shallow, massive salt interval are known, this equation can be solved to result in an estimate of the additional stress due to non-gravitational factors.
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The fracture pressure in shallow, massive salt formations has been elusive. Many operators strive to set a casing shoe at least 500 ft into a massive salt zone and typically will not take a fracture integrity test to leakoff. Fracture of the salt in a shallow clastic formation is feared. If this happens, many believe that the fracture will progress to non-salt areas or that salt will leach away due to drilling fluids moving along the fracture path. Formation pressure tests in salt are often limited to a maximum value of about 1.0 psi/ft to prevent these problems and formation integrity tests are seldom run to fracture.
Case Study Central Mississippi Canyon In early 1990 Exxon drilled the first deepwater subsalt well in 4,352 ft of water in Mississippi Canyon Block 211. A shallow salt layer covers the entire block with the top of salt near 6,000 ft and the bottom of salt near 9,000 ft. The initial exploration well was drilled roughly 500 ft into the top of the salt with a saturated brine drilling fluid which was discharged at the mud line as drilling progressed. After setting the 20 in. casing, a formation integrity test was performed to 10.6 ppgequivalent mud weight (emw) with no leakoff. This test was about 115 psi higher than the predicted fracture gradient at this depth if salt were not present. Drilling progressed to 8,030 ft where a string of 16 ½-in. casing was set. A formation integrity test was run to 12.2 ppgemw with no leakoff, which was about 200 psi more than the expected fracture pressure if salt were not present. This string was set primarily because of the uncertainty of the pore pressure that would be encountered under the salt and the uncertainty with the integrity of the salt just below the 20 in. casing. After the salt was exited, drilling continued to 10,010 ft where a string of 13 5/8-in. casing was set. An appraisal well was drilled in this field in late 1997. The 20 in. casing was set about 550 ft into the top of the salt. A formation integrity test was performed below this string (in the top of the salt) to a maximum 11.8 ppg-emw with no leakoff. This test was about 500 psi higher than the predicted fracture gradient at this depth if salt were not present. The clastic formation was drilled for almost a thousand feet below the salt before the next casing string was set. Data gathered from the original exploration well was used to confirm the ability to drill the salt and exit the salt with only the 20 in. casing set. The savings from eliminating a string of casing in salt is estimated to be seven to eight rig days. Note that the mud weight used when exiting the salt was 88 percent of the estimated fracture gradient. Fig. 5 shows the mud weight and pore pressure data for the well with the estimated fracture gradient for non-salt formations in the southern Mississippi Canyon. Three additional subsea development wells were drilled in the field starting in the fall of 2000. The 20 in. string was set into the top of the salt. The salt formation at the casing shoe was tested to 11.8 ppg-emw without exceeding leakoff. This test was about 500 psi greater than the estimated fracture gradient if salt were not present and 1.2 ppg higher than the formation integrity test performed on the exploration well. Drilling progressed through and below the salt and the next string was set about 400 to 700 ft below the bottom of the salt.
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At this depth mud weight was raised due to increasing pore pressure. This case history occurred before a good method was available to estimate the fracture gradient in a shallow salt interval. We now believe the formation integrity at the top of salt would be higher than the 11.8 ppg-emw test, perhaps as much as 13.0 ppg-emw. The maximum mud weight required to drill all the objectives in a development well is 11.8 ppg. This indicates it may be possible to eliminate the intermediate string of casing used in previous development wells provided lost returns and hole problems are not encountered. Elimination of the intermediate casing string would save seven to eight rig days.
Case Study Southern Mississippi Canyon Well In the winter of 2001 ExxonMobil drilled a subsalt well in the southern Mississippi Canyon area of the GOM. The well was in 6,700 ft of water and salt was encountered from 10,100 ft to 15,495 ft. Since the top of the salt was just over 3,300 ft below the mudline, a 22 in. string was set at 10,185 ft. Operational limitations permitted the 22 in. shoe setting depth to be only 85 ft below the top of the salt. A fracture integrity test at the 22 in. shoe resulted in a very low leakoff pressure and the shoe was squeezed cemented three times. The final formation integrity test was run to leakoff and a 13.8 ppg-emw was indicated. This test was performed to values that were significantly over the predicted formation fracture pressure had salt not been present. Fig. 6 is the final formation integrity test performed just before drilling the balance of the salt interval. The salt was exited at 15,560 feet while drilling with a 12.8 ppg mud weight. After drilling to 15,560 ft, mud losses started but drilling was able to continue to 15,805 ft. At this depth mud losses became extreme even when not drilling or circulating. A string of 13 5/8-in. casing was eventually set in the salt at 15,160 ft in a 12.7 ppg mud weight. The formation integrity test at the 13 5/8-in. shoe, with clastic formations open below the salt, was run to leakoff and resulted in a 13.6 ppgemw. Drilling resumed with a 12.6 ppg mud weight which was maintained while exiting the salt. While drilling, mud weight was raised to 12.9 ppg at 15,900 ft and to 13.1 ppg at 16,465 ft as pore pressure increased. In total, over 13,000 barrels of the synthetic base mud were lost to the well from the time salt was exited until reaching 16,465 ft where an 11 7/8-in. liner was set. After setting the 11 7/8-in. liner, an integrity test was run to leakoff and indicated a 13.8 ppg-emw. The shoe was squeezed cemented and a second formation integrity test was run to leakoff. It indicated a 14.0 ppg-emw. A formation pressure later obtained with wireline logging indicated a 13.5 ppg pore pressure at 16,500 ft. Drilling of the well continued to 26,000 ft with one additional liner set near 22,600 ft in the well. This well required a total of 89 drilling days from spud to reaching total depth. It is thought that the formation integrity obtained at the 22 in. shoe of 13.8 ppg-emw was impacted by the three cement squeeze attempts. The more likely formation integrity at the 22 in. shoe in salt is thought to be near 12.8 ppg. This is the mud
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weight where massive lost returns occurred after exiting the salt. Assuming a 12.8 ppg-emw formation integrity at the 22 in. shoe, the formation fracture pressure would be roughly 6,700 psi. The estimated fracture pressure for clastic formations at this depth is near 5,700 psi. This leaves about 1,000 psi for additional stress in the salt due to nongravitational factors. Fig. 7 shows the pressure vs. depth data for the well with the basic assumption that non-gravitational stress in the salt is 1,000 psi. Note the very narrow margin between mud weight and formation integrity at the bottom of the salt in this case history. Only about a 0.5 ppg existed between the fracture pressure and the mud weight at the 13 5/8-in. shoe when the 11 7/8-in. liner was subsequently set. The mud weight required to drill just under the salt was about 95 percent of the estimated fracture gradient.
Well Design in Shallow Salt Sections At shallow, below mudline well depths, the non-gravitational stresses in a salt formation will increase the formation fracture pressure significantly. As well depth increases, the impact of non-gravitational stresses in salt on fracture pressure decreases. This is shown in Fig. 8. This is the reason shallow salt zones have such a high fracture pressure as compared to the overburden than is observed in deeper salt intervals. To the well planner, the benefit of setting a casing shoe in a shallow salt interval is higher than setting a casing shoe in a deeper salt zone. The gain in formation integrity from non-gravitational stresses in salt formations can be compromised in some cases. When drilling a salt interval that is fractured or when sutures are encountered, lost returns often occur. Therefore, well planners should avoid these geologic features when drilling in salt. After exiting a shallow salt zone and entering typical formations, the increased fracture strength of a salt zone is lost. As a result, there is a drop in formation integrity. In many cases, the formation integrity just under the salt will be a well design constraint. A high formation strength at the top of the salt may not have much value if formation strength just under the salt is low. Obviously, the longer the section of salt drilled, the further hole sections can extend and the potential for reducing casing string increases. From a purely drilling and cost perspective, the optimum length of salt drilled would be that length of salt where the salt is exited when the fracture gradient at the top of the salt is very near the fracture gradient in the formations just below the salt. In the above case histories, the mud weight when exiting the salt was between 88 to 95 percent of the estimated formation integrity just below the salt. Exiting the salt with a mud weight in this range has proven successful when drilling massive, shallow salt zones in the Mississippi Canyon area of the GOM. It is thought that exiting salt with lower mud weight will often result in being underbalanced to pore pressure. Resulting hole problems are often attributed to a rubble zone rather than being underbalanced to pore pressure. A mud weight higher than
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about 95 percent of formation fracture strength will likely result in lost returns or a ballooning formation. When a casing string is set into the top of a salt interval, the presence of the salt will affect the design of the casing. Since the fracture pressure in salt is higher than a comparable nonsalt formation, the casing must be designed to safely handle the pressures resulting from well control incidents which can be encountered in the salt or below the salt.
Conclusions 1.
Formation integrity in shallow GOM salt formations has been observed to be reliably higher than the fracture pressure expected in a non-salt formation. For this to occur, salt must have stresses opposing fracturing that are due to non-gravitational stresses. It is thought that these stresses in salt are attributable to the limited tensile strength of salt and residual stresses due to tectonics or other factors.
2.
Experience in the deepwater GOM indicates that shallow salt has approximately 1,000 psi of non-gravitational stress. This stress can be relied upon to increase formation integrity when in salt.
3.
Drilling shallow salt zones in deepwater GOM wells has proven a method to reduce the number of casing strings in a well and reduce well costs.
4.
When exiting shallow salt formations, a mud weight of about 88 to 95 percent of estimated formation integrity just below the salt has proven to be successful.
5.
The difficulties of drilling massive, shallow salt zones have been overcome with improved technology. As a result, many operators now seek out massive, shallow salt intervals as a way to reduce drilling costs.
Acknowledgments We would like to acknowledge ExxonMobil Drilling management including Pete Altimore, Carl Sandlin and Miles Peroyea who supported this paper being written. We would also like to acknowledge Fred Dupriest who offered many valuable suggestions that improved this paper.
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References 1. Halbouty, M.T.: Salt Domes, Gulf Region United States and Mexico, Second Edition, Gulf Publishing Company, Houston, 1979. 2. Diegal, F.A. et al : "Cenozoic Structural Evolution and TectonoStratigraphic Framework of the Northern Gulf Coast Continental Margin," Salt Tectonics: A Global Perspective , M.P.A. Jackson, D.G. Roberts and S. Snelson, eds., AAPG Memoir 65, (1995) Chap. 6, 109-151. 3. Cromb, J.R.: “Deepwater Subsalt Development: Directional Drilling Challenges and Solutions,” paper IADC/SPE 59197 presented at the 2000 IADC/SPE Drilling Conference, New Orleans, Louisiana 23-25, February. 4. Willson, S.M. and Fossum, A.F.: “Assessment of Salt Loading on Well Casings,” paper SPE/IADC 74562 presented at the 2002 IADC/SPE Drilling Conference, Dallas, Texas 26-28, February. 5......Whitson, D. and McFadyen, K.: “Lessons Learned in the Planning and Drilling of Deep, Subsalt Wells in the Deepwater Gulf of Mexico,” paper SPE 71363 presented at the 2001 SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana 30 September - 3 October. 6. ..Meize, A. et al : “Record Achieved on Gulf of Mexico Subsalt Well Drilled with Synthetic Fluid,” paper SPE 59184 presented at the 2000 IADC/SPE Drilling Conference, New Orleans, Louisiana 23-25 February. 7. Worrall, D.M. and Snelson, S.: “Evolution of the Northern Gulf of Mexico, with Emphasis on Cenozoic Growth Faulting and the Role of Salt,” The Geology of North America, Vol. 1. The Geology of North America – An Overview, The Geology Society of America, 1989, Chapter 7, 97-138. 8. Hardy, R.H. et al .: Theoretical and Laboratory Studies Relative to the Design of Salt Caverns for the Storage of Natural Gas, American Gas Association, Arlington Virginia (1982). 9. Barker, J.W., Feland, K.W., and Tsao, Y.H, “Drilling Long Salt Sections Along the US Gulf Coast,” SPE Drilling and Completion, (September 1994), 185. 10.....Warpinski, N.R. and Smith, M.B: “Rock Mechanics and Fracture Geometry,” Recent Advances in Hydraulic Fracturing , J.L. Guidley et al (eds.) Monograph Series, SPE, Richardson, Texas (1989), vol. 12, 57-80. 11. Barker, J. W.: “Estimating Shallow Below Mudline Deepwater Gulf of Mexico Fracture Gradients,” paper presented at the 1997 Houston AADE Chapter Annual Technical Forum, 2 - 3 April. 12. Rocha, L.A. and Bourgoyne, A.T.: “A New Simple Method To Estimate Fracture Pressure Gradient,” SPE Drilling & Completion (September 1996) 153. 13. Aadnoy, B. S.: “Geomechanical Analysis for Deep-Water Drilling,” paper IADC/SPE 39339 presented at the 1998 IADC/SPE Drilling Conference, Dallas, Texas 3 - 6 March.
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Fig.1. Structural summary map of the northern Gulf of Mexico Basin. Black areas are shallow salt bodies. From AAPG Memoir 65, Diegal, F.A., et al.: AAPG©1995, "reprinted by permission of the AAPG whose permission is required for further use".
Fig. 2. General geologic cross section of Gulf Coast Basin.
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Fig. 3. Typical stress-strain curves.
Fig. 4. Estimated non-salt formation fracture gradient, deepwater central and southern GOM.
Fig. 5. Central Mississippi Canyon well pressure vs. depth.
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Fig. 6 - Southern Mississippi Canyon well, formation integrity test at 22 in. shoe in salt.
Fig. 7 - Southern Mississippi Canyon well pressure vs. depth.
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Assumption: Added Salt stress = 1,000 psi
Assumption: Added Salt Stress 1,000 psi
Salt: 13,500 - 16,000 ft
Fig. 8 - Impact of salt depth on estimated fracture gradient.
