Ft Of Shale Research Articles

Managed-Pressure-Drilling Technology Succeeds in the Harding Field

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 166170, ’Managed-Pressure Drilling, Casing, and Cementing Enable Success in Conventionally Undrillable Wells in the Harding Field,’ by Mohamed A. Mashaal, Tom Fuller, Chris J. Brown, and Robert Paterson, BP, prepared for the 2013 SPE Annual Technical Conference and Exhibition, New Orleans, 30 September-2 October. The paper has not been peer reviewed. This paper presents a case history of a North Sea well in which managed-pressure drilling (MPD) was used as the enabling technology to drill, case, and cement the well, with particular focus on the planning process, design methodology, and execution particulars. A novel fluid-pressure- transmission pill (FPTP), composed of a crosslinked polymer, was also used to maintain hydrostatic pressure while tripping bottomhole assemblies (BHAs) and during deployment of the liner and sand-control equipment. Background and Drilling Challenges The Harding field is a mature North Sea platform development upon which an infill-drilling project has been initiated to access the remaining oil. This oil tends to lie in more-distant, hard-toreach targets, including those in the far north of the field and a new field located south of the platform. These would be accessed by extended-reach-drilling (ERD) wells. A combination of reservoir depletion and weak interbedded sands and shales has resulted in a further reduction in the already narrow mudweight (MW) window between fracture and formation-collapse pressures. The window had decreased from 2 to 0.7 lbm/gal, equivalent to a 200-psi bottomhole- pressure (BHP) window. ERD to access the oil accumulations most distant from the platform would generate equivalent circulating densities that are 50% greater than the available MW window, so these wells are not conventionally drillable. After MPD proved to be an effective strategy for a test well (IC6) in the Harding field, the decision was made to apply MPD to two ERD wells (PNE4 and PNE2) that had not achieved their objectives. A subsequent investigation into the shortcomings of these wells led by the subsurface team resulted in a reworking of the pore-pressure/fracturegradient predictions for the northeast of the field, taking the depletion in that part of the reservoir into account. Sand/ shale interfaces at the margins of the reservoir, and sand/sand interfaces created by the injection of sand through the main reservoir body, also appear to result in localized fracture-gradient reduction. These combined factors resulted in a reduced MW window compared with that previously used in well planning. Hydraulics modeling strongly suggested that drilling PNE2a (the redrill of PNE2) would be unachievable conventionally, and drove the decision to use MPD for the reattempt. PNE2a would include a 12¼-in. overburden section, a highly challenging prospect containing more than 6,000 ft of shale, as well as the 8½-in. reservoir section, which was expected to have significant sections of shale where instability had previously caused drilling problems (see Fig. 1).

Comments: Brazil's New Finds

Editor's column For an example of one of the new breed of successful national oil companies, look no further than Petrobras. Well known for technology expertise and innovation—the company has won two Offshore Technology Conference (OTC) awards for technical achievement—the Brazilian company is now making news for what could be some of the biggest oil discoveries in years. Petrobras' Tupi discovery, located more than 150 miles in deep water off the Brazilian coast, has estimated recoverable reserves of between 5 and 8 billion bbl. That would make it one of the most significant finds in the past 20 years, according to analysts Wood Mackenzie, rivaling the 2000 Kashagan discovery in Kazakhstan and surpassing the largest deepwater finds, including those in the US Gulf of Mexico and offshore west Africa. Initial production of 100,000 BOPD could begin in 2010. Petrobras has announced a series of oil discoveries in the Santos basin in recent months, including the natural gas field Jupiter and the subsalt field Carioca, which has drawn considerable speculation about its size. At this year's OTC, Petrobras Chief Executive Officer Jose Sergio Gabrielli, while acknowledging the importance of the deepwater discoveries, would not speculate on potential reserve figures. If the promise of Tupi holds, Brazil would boost its reserves by 50% and join the ranks of the world's most significant producers. Already there is speculation that Brazil might eventually join OPEC. Petrobras' rise has been steady since it was partially privatized by the Brazilian government in the late 1990s. The country only recently became energy self-sufficient and now produces more than 2 million BOPD, almost 90% of it offshore. The company expects output to rise to 3 million BOPD by 2012 and 4 million BOPD by 2015. Petrobras believes that Tupi may be just part of a huge subsalt cluster extending hundreds of miles along the Brazilian coast. Brazil's new oil finds will not be easy, or inexpensive, to develop. Although Brazil is considered a global leader in offshore development, the Tupi basin is located under 7,000 ft of water and then under 9,200 ft of shale and salt. Seismic imaging will be difficult and may hamper accurate estimation of reserves, and drilling challenges are common in subsalt. With regard to the Carioca area, Petrobras is at the beginning of its evaluation plan and will not have precise volume estimation until after finishing the plan. The company's success could put a strain on already tight equipment and talent markets. Petrobras, which already has leased most of world fleet of vessels for deepwater drilling, plans to lease more and also hire thousands of upstream personnel as it creates a new division for subsalt drilling.

Development of the Alba Field—Evolution of Completion Practices, Part 2: Openhole Completions, Conventional Gravel Packing After Drilling With SOBM

Summary Chevron has been successfully drilling and gravel packing openhole horizontal wells in the Alba field (central North Sea) since 1998, and 13 openhole gravel-packed (OHGP) wells drilled with water-based mud (WBM) are currently in production with no history of sand production. Although these wells have been hugely successful with significant net present value (NPV) returns, it was recognized that the future, mature redrill and infill targets cannot sustain the current costs associated with traditional OHGP completions. The challenge was to develop alternative techniques to maintain the benefits of OHGP wells but to achieve a low-cost well and completion concept to assist in realizing new drilling opportunities. Drilling the shale above the top of the reservoir and the productive interval in a single hole section would require removing conventional requirements for setting an additional casing string and changing over to a water-based system before drilling into the reservoir. This would save costs but raises a question concerning the gravel-packing operation. Hitherto, attempts to gravel pack that involve alpha/beta placement techniques using an aqueous carrier fluid following drilling with oil-based systems have had only limited success. The prospective problems were examined by extensive laboratory tests carried out cooperatively by Baroid and Chevron. A new, synthetic oil-based mud (SOBM) formulation was developed, and compatible displacement fluids and procedures were devised. Based on this work, 1,500 ft of shale and reservoir were drilled, a liner that was predrilled over the reservoir section was installed, and screen was run inside the liner. Gravel was pumped using brine as the carrier fluid, and complete gravel placement was achieved. The well has achieved productivity levels at least as good as existing WBM wells. A second well completed in the same manner has given a similar performance. This combination of a liner system and SOBM fluids offers several advantages. There is the prospect of considerable savings with respect to operating time, cementing, and drilling fluids. The liner also gives protection to the screen. This new approach, which represents potential large savings in costs and excellent productivity, is considered applicable to other types of completions when it is desirable to drill with oil-based mud even though conventional thinking would have called for water-based drill-in fluid. This consideration applies to targets in the Alba field and worldwide.

Reservoir Description is Key to Steamflood Planning and Implementation, Webster Reservoir, Midway-Sunset Field, Kern County, California: ABSTRACT

The Webster reservoir at Midway-Sunset field, Kern County, California, is an unconsolidated sand reservoir of Miocene age (''Stevens equivalent,'' Monterey Formation). The Webster was discovered in 1910 but, due to poor heavy oil (14/sup 0/ API) economics, development for primary production and subsequent enhanced recovery were sporadic. Currently, the reservoir produces by cyclic steam stimulation in approximately 35 wells. Cumulative oil production for the Webster since 1910 is about 13 million bbl. The Webster is subdivided into two reservoirs - the Webster Intermediate and Webster Main. The Webster Intermediate directly overlies the Webster Main in one area but it is separated by up to 300 ft of shale elsewhere. The combined thickness of both Webster reservoirs averages 250 ft and is located at a drilling depth of 1,100-1,800 ft. From evaluation of modern core data and sand distribution maps, the Webster sands are interpreted to have been deposited by turbidity currents that flowed from southwest to northeast in this area. Oil is trapped in the Webster reservoir where these turbidites were subsequently folded on a northwest-southeast-trending anticline. Detailed recorrelation on wireline logs, stratigraphic zonation, detailed reservoir description by zone, and sedimentary facies identification in modern cores has led to developmentmore » of a geologic model for the Webster. This model indicates that the Webster Intermediate was deposited predominately by strongly channelized turbidity currents, resulting in channel-fill sands, and that the Webster Main was deposited by less restricted flows, resulting in more lobate deposits.« less

A Review of Waterflood Performance in Garrington Cardium A and B Pools, Unit No. 2

This paper presents the evaluation and prediction of ultimate oil recovery after a petrophysical study of Garrington Cardium A and B pools. Reservoir sands are discussed in detail and waterflood performance is emphasized. Surfactant treatment to improve oil production is described. Introduction The Garrington Upper Cretaceous Cardium field is located about 60 miles northwest of Calgary (Fig. 1) and has two pools, upper Cardium A and lower Cardium B sandstones, separated by about 100 ft of shale. Both sands trend northwest-southeast. Sand A trends for 36 miles with a producing width of about 6 miles. Sand B trends for 42 miles with a maximum width of 1 1/2 miles (Fig. 1). Thicknesses vary, but the maximum is about 20 ft in both pools. The field was discovered in 1954 and waterflood operations began in 1965. This field has four units, but this study discusses only the geology and waterflood performance of Unit 2 (Fig. 1). Knowledge of the origin and performance of Unit 2 (Fig. 1). Knowledge of the origin and postdepositional history of these sands leads to a better postdepositional history of these sands leads to a better understanding of the waterflood performance. Basic rock types were determined by examining detailed cores, measuring mercury-injected capillary pressure, and scanning electron microscope. Rocks were pressure, and scanning electron microscope. Rocks were classified as "good" or "poor" in terms of reservoir potential. Significant differences in the production and potential. Significant differences in the production and waterflood history of Sands A and B can be related to their geological characteristics. Geology Cardium A sand correlates with the producing sand of Pembina field 60 miles northwest. However, it is thinner Pembina field 60 miles northwest. However, it is thinner with poorly developed, clean sand beds. The most distinctive feature of Sand A is the extensive mottling caused by burrowing organisms that mixed sand, silt, and mud together. This action greatly reduced the effective porosity and, particularly, the permeability of the sand; porosity and, particularly, the permeability of the sand; but, more importantly, it destroyed much of the lateral continuity of the sand beds. Thinly laminated, well sorted, clean, fine-grained sandstones are seldom more than 1 to 2 in. thick. Sandstones are composed mostly of quartz and lesser chert grains, with only minor amounts of feldspar, mica, and rare glauconite. X-ray diffraction analysis shows that the dominant clay minerals are illite, chlorite, and kaolinite, with traces of montmorillonite. The kaolinite is well crystallized and probably of diagenetic origin. At the top of the Sand A sequence, there is usually a conglomerate bed that varies from 1 in. to nearly 3 ft thick. This is composed of well rounded chert, quartz, and argillite pebbles embedded in a dense shale matrix. Although nonporous, the conglomerate has well developed, vertical fractures. Laterally, Sand A grades into siltstones and silty shale. Textures and structures indicate that Sand A was deposited in a shoreface environment. Comparison of this conglomerate with that at Pembina and elsewhere indicates that the beds formed as bars on top of an offshore shoal, possibly as a terrace bar, as suggested by Swagor et al. for Cardium conglomerate at Carrot Creek. Sand B is different both in distribution and mineralogy. Its most striking feature is the length of its body relative to width. JPT P. 869

H-Bearing Piles in Limestone and Clay Shales

A pile test program was used to finalize the foundation design for railroad bridge piers founded on H-bearing piles driven through alluvial and glaciofluvial deposits in bedrock of the Pennsylvania system. Twenty-four test piles were driven for length determination and 14 piles were extracted to check for damage while driving. The design bearing capacity was verified with 10 static load tests. Adequate bearing could be obtained for a design pile load of 50 tons by either founding on a thin hard limestone stratum or driving into about 10 ft of shale. The pile capacity was not significantly altered by remolding of the shale or breakup of the limestone strata. The pile extraction program showed piles were damaged if driven through limestone strata.

Carbon Dioxide Test at the Mead-Strawn Field

Core data and production histories from the CO2 test flood area, compared with similar data obtained from areas that had been water flooded, confirmed the results of laboratory experiments, which had shown that a CO2 flood recovers 50 to 100 percent more oil than a conventional water flood. Introduction A field pilot project has been conducted to test the effectiveness of carbon dioxide as an oil recovery agent in a primary-depleted reservoir. Our experimental oil recovery process consisted of injecting a small slug of CO2 (4 percent PV) followed by a slug of carbonated water (12 percent PV) and then brine. Prior to CO2 injection, water was injected to raise the reservoir pressure in the test area from about 115 to 850 psi; the objective was to maintain the average reservoir pressure at a minimum of 850 psig throughout the test to ensure maximum effectiveness of the CO2. The test was run in a small area of the Upper Strawn sand in the Mead field located in Jones County, near Abilene, Tex. Oil is produced from two zones in the Strawn sands; these zones are separated by about 400 ft of shale and lime. Approximately 2,000 acre-ft to the south and west of the CO2 pilot in the Upper zone, and all 2,000 acre-ft of the Lower zone, were waterflooded conventionally at the same time the CO2 flood was being conducted. Geological Description of the Sands The Upper and Lower Strawn sands are Pennsylvanian in age and are at depths of 4,500 and 4,900 ft, respectively. Both Strawn sands occur as northeast-southwest trending bars or strand lines in which irregular elongate, lenticular porosity traps were developed. The traps are controlled by pinchouts of porosities and permeability in all directions. The sands usually are poorly developed, and are both limey and shaly, with porosities and permeabilities uniformly low. They contain abundant, thinly interbedded shales and subordinate, thin limestone stringers. There is no known oil-water contact in the Mead-Strawn sands. Structural attitude is monoclinal, with a dip of 80 to 100 ft/mile in a northwesterly direction. The hydrocarbon traps occur independently of structure. A petrographic analysis showed the rock to be a sandstone of fine to very fine grain. The average grain size is 0.1 to 0.18 mm, and the grains are mainly subangular and fairly well sorted. The quartz grains have important amounts of secondary growth, which reduces porosity and permeability. The sandstone is very clean, with little matrix material. Field Information Figs. 1 and 2 are isopachous and structural maps of the Upper Strawn sand. The Mead field was discovered in March, 1951, with the completion of the R. A. McCollum No. 1, Sec. 15, Block 17, T and PRR survey. Solution gas furnished the primary drive mechanism. At the start of the waterflood and CO2 test flood, oil production from the areas to be flooded averaged less production from the areas to be flooded averaged less than 40 B/D, and reservoir pressure was about 115 psig. psig. The following are the properties of the entire Upper Strawn sand reservoir in the Mead field: JPT p. 431

CARBONIFEROUS ROCKS OF THE CONCHE – GROAIS ISLAND AREA, NEWFOUNDLAND

About 5 000 ft of Carboniferous sedimentary strata occur in the Cape Rouge and Conche peninsulas, small projections on the east side of the Great Northern Peninsula of Newfoundland. The lower 900 ft of the section consists of coarse conglomerate and sandstone, the fragments in which were derived from nearby older rocks. These lower beds are overlain by about 4 000 ft of shale and sandstone, in places petroliferous and with bituminous residues, and bearing plants and spores identified as of upper Horton (late Tournaisian) age. The sedimentary rocks described in this paper are the northernmost known Carboniferous rocks of the Appalachian belt. They lie in a basin between Groais Island and the Great Northern Peninsula and may possibly be continuous under the sea with the Grand Lake–White Bay basin a 100 mi to the southwest. The boundary fault on the west side of this Carboniferous basin is a portion of a fault system which is known to extend some 300 mi from the northern tip of Newfoundland to its southwest corner and is a portion of the Cabot fault of Wilson. Movement on the fault system appears to have been of at least three ages, pre-Horton (pre-Tournaisian), post-Horton–pre-Windsor (post-Tournaisian–pre-Visean), and post-early Pennsylvanian (post-Westphalian "A").

Underground Combustion in the Shannon Pool, Wyoming

Abstract A pilot test of forward combustion in the Shannon pool, Salt Creek field, Wyo., is described. The Shannon sand, 950-ft deep, contains a heavy (25 API), viscous (76 cp) oil. Natural reservoir energy is limited. Primary production, intermittent since 1889, recovered only about 2 per cent of the oil in place. The field is operated by Pan American Petroleum Corp. for the Midwest Oil Corp., the owner. The original pilot was a 1.32-acre five-spot. The expanded pilot has eight producing wells surrounding a roughly triangular area of about five acres with the injection well near the center. A control or comparison well was also recompleted in another part of the field. Operation of the pilot has been little different from an ordinary gas drive. Little special equipment was found to be absolutely necessary. Except for some use of a temperature-resistant cement, all wells were conventionally completed. In spite of poor oxygen consumption, the over-all performance of the pilot has been good. Total oil recovery to June 1, 1961, was 73,971 bbl. The wells of the original pilot alone had produced about 24,000 bbl, equivalent to 50 per cent of the oil in place, when fire breakthrough at the first well occurred. These wells have now produced oil equivalent to more than 74 per cent of the oil in place in the original pilot area and production is continuing. It appears that ultimate recovery will approach theoretical maximums before the wells must be abandoned. Performance of the pilot has been encouraging, and expansion to a fieldwide combustion operation is being investigated. Introduction The results of both laboratory investigations and field tests of underground combustion have been reported previously. However, most of the field tests were primarily experimental. More information and experience are needed before forward-combustion operations can be engineered with confidence. The purpose of this paper is to present the results of a successful pilot test of forward combustion. These results should increase confidence in forward combustion as a practical method for commercial oil recovery. HISTORY OF THE SHANNON POOL The Shannon pool is located on the north end of the Salt Creek field in Natrona County, Wyo. It is approximately 50-miles north of the city of Casper. The Shannon pool discovery well was completed in 1889, making this one of the oldest oil fields in the Rocky Mountain region. Three more wells were drilled in 1890. First production was hauled in wooden barrels by horse and wagon to the railroad in Casper. In 1894 a small refinery, the first in Wyoming, was built in Casper to process the Shannon crude. In the following years the field changed hands several times. It appears that each new owner did some development drilling as several wells were completed in each of the years 1895, 1902, 1905 and 1912, with negligible development in the intervening years. Forty-eight wells were drilled in this period, but many were later abandoned. Discovery of the more prolific Salt Creek field proper ultimately forced suspension of operations at the Shannon pool. After 1915 there was only sporadic production, mostly to supply cheap boiler fuel to drilling rigs in the Salt Creek field. But even this was discontinued in 1931. Since then the pool had been dormant until the recent operations, which are the subject of this paper. The Shannon pool is now owned by the Midwest Oil Corp. Field operations are conducted for Midwest by Pan American Petroleum Corp. THE RESERVOIR Fig. 1 is a map showing subsurface contours of the Shannon pool. The reservoir is on a nose of the Salt Creek anticline dipping to the north at about 500 ft/mile. The trap is provided by a shallow fault on the updip side of the productive area. The downdip limits are bounded by water, but this water has not provided an effective source of reservoir energy. The Shannon sand outcrops at many places in the immediate vicinity, providing good surface indications of the Salt Creek anticline. At the Shannon pool the sand has been lowered by faulting and is overlain by about 900 ft of shale and other sands. The Shannon sand consists of two members. The upper, a water sand, is about 40-ft thick and is separated from the lower member by several feet of sandy shale. JPT P. 197^

Twelve Years of Gas Injection in a Frio Sand

Introduction The purpose of this paper is to contribute to the existing knowledge of the economic recovery of oil by methods other than normal depletion. A case history is presented of a gas injection project in one zone of the multiple producing zone Frio sands of south Texas. Approximately 75 per cent of the produced gas has been returned to the formation for 12 of the 13 years of producing life. The study is an example of the performance which has been experienced by return of a large portion of the produced gas to the gas cap of a thin non-homogeneous sand. Geology The producing zone is the Frio sand of lower Oligocene age. The oil and gas accumulation is a combination of a structural and stratigraphic trap. The structure consists of a large asymmetrical nose plunging gently to the northeast. The reservoir is limited on the west flank by an oil-water contact, on the north and south by the sand lens grading into shale, and on the east by a steep fold or fault parallel to the axis of the structure. The dip of the west flank or oil producing flank is approximately 130 ft per mile, or only 1.5 degrees. There are 11 separate Frio producing zones in the field but this paper is limited to only one of the zones. The sand lenses are separated vertically by 25 to 75 ft of shale and were correlated across the field by means of markers picked from the electric logs. A portion of a typical cross section is shown on Fig. 1 and the section is located with reference to the area on Fig. 2. The D-5 reservoir is the large sand lens which appears in the D zone on the cross sections. It covers an area of approximately 2,100 acres. The structural map of the D zone (Fig. 2) was contoured on the subsea correlation points on the top of the D zone. The reservoir rock is predominately firm, medium to fine-grained gray, argillaceous sandstone but lenses of soft, loosely consolidated sandstone occur throughout the producing zone. An x-ray diffraction indicates the clay content to be chiefly of the montmorillonite group and solubility tests indicate a low carbonate content. The porosity ranges from 8 to 28 per cent with a weighted average of 23 per cent. The majority of the horizontal permeability ranges from 100 to 500 md and averages 194 md. The vertical permeability is approximately one-half of the horizontal permeability.