ARCO Oil Research Articles

Assessing the effectiveness of local organic materials as sorbents for oil spill response in Arctic waters

The paper presents the results of a comparative assessment of the sorption characteristics of regional natural raw materials of organic origin: sphagnum moss (Sphаgnum palustre L.), fucus algae (Fucus vesiclousus), a composite based on them and peat in comparison with the synthetic sorbent OilSorb used in the practice of emergency rescue units to eliminate accidental oil spills. Experimental data have been obtained on potential pollutants in the Barents Sea (oil ARCO and diesel fuel) and the water capacity of sorbents for standard conditions at temperatures of 21–23 °C according to GOST 33627-2015 and in the temperature range of 10–12 °C typical for the summer period on the Kola Peninsula. The sorption characteristics of the materials under study have been evaluated in the "sea water – petroleum product" system, which simulates a real oil spill in the marine area. Tests in a model system simulating real conditions demonstrate significant changes in the efficiency of using sorption materials shown by them under standard conditions. The study has established the dynamics of the distribution of sorbed oil products and water in the materials under consideration, as well as residual oil products in the water of the "sea water – ARCO oil" and "sea water – diesel fuel" systems at different exposure times. During an exposure time of 30, 60, 90 minutes under the conditions of a system simulating a real oil spill in the water area, the material based on sphagnum moss has the most effective and time-stable indicators of sorption of oil products.

Outstanding student papers

Two presentations in the Ocean Sciences Section were named Outstanding Student Papers at AGU's Spring Meeting in Baltimore, Md.Walter Borowski, who presented “Gas Hydrates, Methane Inventory, and Sulfate Profiles: Predicting Methane Flux and Gas Hydrate Occurrence From Sulfate Profiles in Piston Cores,” is a doctoral student in geology at the University of North Carolina at Chapel Hill working with Charles K. Paull. Borowski earned undergraduate degrees at Case Western Reserve University in geology and biology, and an MS in geology from the University of Tennessee, Knoxville. For nine years, he worked as an exploration and production geologist at ARCO Oil and Gas Company. Now his research investigates the effects of gas hydrates on the chemical signatures of pore waters within the continental rise of sediments of the southeastern United States. He will sail as an inorganic geochemist on ODP Leg 164 (Gas Hydrates) later this year.

Regulation of CO2 Waste Fluid Stringent

ARCO Oil and Gas Company operated a gas extraction and processing project. The extracted gas was 96 percent carbon dioxide (CO2) and was used for enhanced oil recovery. The process brought to the surface certain waste fluids that were disposed of in an underground injection well. The US Environmental Protection Agency (USEPA) directed ARCO to apply for a class I permit, which characterized the waste fluids as “hazardous,” “industrial,” or municipal waste. ARCO objected and preferred a class II permit, which characterized the waste as fluid “brought to the surface in connection…with conventional oil or natural gas production.” However, ARCO hedged its bets, applied for and received a class I permit, and then petitioned for a review, which the USEPA denied.

The Live Case Method of Creating the Learning Organization

Presents and examines the “live case method” as an increasingly influential means of broadening the thinking of middle managers, prompting them to adopt senior managerial perspectives on problems currently besetting their organizations. Claims that it is the live‐case orientation of the mid‐management seminar programme involved that provides effective linkage between managerial and organizational learning. Considers the value of the method first in relation to its application with middle managers of the ARCO Oil and Gas Company, highlighting the importance also of senior managerial involvement throughout the seminar programme; and then proceeds to illustrate the method′s use at corporate executive level, citing the extension of the approach in 1993 by ARCO′s Atlantic Richfield operation to their corporate executive seminar. Contends that the method exemplifies and encourages effective organizational learning in action at both middle and senior management levels.

Impact of Dewatering Technology on the Cost of Drilling-Waste Disposal

Summary The use of mobile, chemically enhanced centrifugation dewatering systems toprocess liquid waste from two deep exploratory wells in Kern County, CA, saved $136,900 in waste-disposal costs. Liquid waste in the wells was reduced by 45%. This paper tracks daily costs and chemical usage for each well to isolate keycost factors. Introduction The use of different types of dewatering technology to process effluent fromvarious industries has been well documented. others have reported on the use ofa centralized facility to process drilling waste transported from a number ofdrilling sites to the facility, hut the application of the technology at anactive drilling location has been limited by the complexity of dewatering. Theuse of the technology as an on-line addition to the rig's solids controlequipment has been suggested, but the results of such on-line processing havenot been extensively reported in the literature. This paper reviews the use ofone such dewatering paper reviews the use of one such dewatering technique, chemically enhanced centrifugation, at two active drilling locations. Chemically enhanced centrifugation uses chemical coagulants and flocculants toachieve fine-particle flocculation. The flocculated solids are then separatedfrom the waste stream with a high-speed centrifuge. This solids-separationtechnique differs from conventional "closed-loop" mud systems in oneimportant way: conventional closedloop systems rely on additionalsolidsprocessing equipment, such as "microclones" (small-diameterhydrocyclones), and traditional centrifuges to separate water and solids fromthe waste stream. Processing in this manner generally fails because theadditional solids-processing equipment cannot remove extremely fine particlesfrom the waste stream. When the particles from the waste stream. When therecovered water is returned to the mud system, fine solids are ala returned tothe mud. Continued reuse of the recovered water eventually results in afine-particle accumulation in the mud system that can be corrected only throughmassive dilution. Thus, the objective of waste-volume reduction is defeated or, at least, severely compromised. Chemically enhanced centrifugation, however, removes fine solids by treatment with chemical coagulants and flocculants. In July 1988, Arco Oil and Gas Co.'s Western Dist. began field testing of twodewatering units that used chemically enhanced centrifugation to process liquiddrilling waste. Both units were mobile in the sense that the component partscould be loaded onto two trailer trucks and transported to the drillinglocation for assembly. Both units were comparable in design and operation andwere furnished by the same service company. Before the units were selected, alist of checkpoints that were considered key to the successful operation ofsuch a unit was prepared (see Table 1). Available units were prepared (see Table 1). Available units were compared on the basis of a physical examinationfollowing this list. The unit with the best score was selected for the tests. Operational considerations limited the size of the reserve pit at bothfield-trial locations. The dewatering units were used to create aminimum-discharge (closed-loop) solids-control system. Because the cost ofliquid-waste disposal was $10.85/bbl, the plan was to send all the effluents tothe dewatering unit for processing. The recovered water would be returned asneeded to the mud system, and the solids separated by the centrifuge would bedischarged to the reserve pit. Because this recovered water was to be pit. Because this recovered water was to be reused in the mud system, asuspended-solids content of less than 500 mg/L and a residual-polymer contentof less than 0.1 lbm/bbl in the recovered water were dewatering goals. Thepurpose of these field trials was to assess the ability of the dewatering unitto achieve water-clarity goals for less than $10.85/bbl. This assessment wouldprovide one means of evaluating the economic viability of thisminimum-discharge solids-control system. Well Background Data The Mettler No. 1 was drilled in the Tejon (North) field, Kern County, CA. The dewatering test began July 26 and was completed Oct. 24. The dewateringunit was on location 96 days. Fig. 1 is a schematic of the well's hole size andcasing programs. The Arco-Texaco No. 801 was drilled in the Midway Sunsetfield, Kern County. The dewatering test began Aug. 18 and was completed Dec.20. Difficulty in setting cement plugs for directional control caused the timeplugs for directional control caused the time on location to be significantlylonger than planned (125 days). Fig. 2 is a schematic planned (125 days). Fig.2 is a schematic of the well's hole size and casing programs. JPT P. 730

Area Waste-Management Plans for Drilling and Production Operations

Summary This paper details a process for identifying appropriate waste-managementstrategies in a specific area of operation. These strategies consider currentregulatory requirements, company policies, and economic and practical factors. Management practices covered include minimization, storage, handling, anddisposal. The strategies developed are communicated to field operations througha document specifically designed for effective use by field drilling andproduction personnel. The plan's objectives, development, content, and possiblealternative applications are presented, and examples from the development of anactual plan are given. presented, and examples from the development of anactual plan are given. Introduction One environmental issue receiving significant attention in recent yearswithin the oil and gas E and P industry is the handling and disposal of wastes. Heightened interest within the public and the regulatory agencies towardenvironmental issues has been an impetus for the industry to scrutinize itswastes and how they are managed. From a private company's perspective, properwaste management is an important part of business. A company must be concernedabout complying with applicable waste regulations, minimizing the impact of wastes on the environment, and reducing the disposed-of waste. All these mustbe done within certain economic boundaries. Also, eliminating or minimizingwaste generation is becoming more critical, both environmentally andeconomically, as a means of reducing waste-related liabilities and costs. Thispaper reviews the concept of the area waste-management plan as a means ofimproving the management of wastes generated by a company's drilling and production operations. The development and use of area waste-management plans allow a company to identify and communicate sound waste-management strategies effectively. The strategies are based on regulatory, environmental, technical, and economic criteria applicable to a specific geographic area of operation. Waste-Management Concerns A cursory review of Arco Oil and Gas Co.'s drilling and production operations identified several concerns regarding the handling and disposal ofcertain wastes generated by its operations. Production operations were viewed from a broad scope of operating facilities, including oil production (primaryand secondary), gas production, and gas processing. Drilling operationsobserved included drilling, workover, and completion. These field operationsoccurred in a variety of environmental and regulatory settings. Waste-management concerns generally focused on inconsistent minimization, handling, and disposal practices. Reviews of the operations and interviews withpersonnel revealed the specific reasons for these concerns. The primary reasonfor the concerns was an inadequate understanding of the wastes and themanagement options available. This misunderstanding was the result of severalfactors, including complex and changing regulations, unclear guidance on theenvironmental aspects of field operations, and the perception of competingenvironmental and economic goals. Regulatory Climate. Most state oil and gas agencies began regulating wastefrom drilling and production operations before the U.S. government started topass environmental statutes in the early 1970's. Historically, regulation of oilfield wastes has focused on drilling fluids and produced water. Since theearly 1970's, a number of federal and state environmental statutes andregulations have been passed that affect the management of oil and gas waste. Each state has developed regulations to control these wastes as specified inthe federal laws and as specified in the state's own environmental statutes. Though adequate, states' requirements for oil and gas waste management varysignificantly, reflecting the diverse geological and environmental conditionsin each state. Because of the historical emphasis on drilling fluid andproduced water, the regulations often are not specific on a waste-by-wastebasis. For operations on federal lands, companies must comply with separate.sometimes overlapping, regulations administered by different federal agencies(e.g., U.S. Bureau of Land Management and the U.S. Forest Service) in additionto the state's requirements. Also, the regulations have been amended frequentlyover the last 10 years. This complex regulatory climate, which changes withtime and geopolitical boundaries, contributes significantly to the lack ofunderstanding of requirements affecting waste management in the oil field. JPT p. 67

Evaluation of Untested Stratigraphic Traps in a Pleistocene Canyon-Fill Complex, Offshore Louisiana: ABSTRACT

Eugene Island Block 390, located approximately 100 mi offshore Louisiana was acquired by ARCO Oil and Gas Company in 1983 to test upper Pleistocene amplitude anomalies located on the faulted northwest flank of a diapiric salt structure. Although drilling has established the presence of oil and gas in the objective section, an attempt to delineate further reserve potential on the block was made by evaluating additional amplitude anomalies located downflank in an adjacent syncline. Seismic stratigraphic analysis indicates that the anomalies are located within the confines of an erosionally incised submarine canyon complex, approximately 3 mi wide and 500 ft deep. A number of high-amplitude events located in the upper part of the fill complex are interpreted to represent relatively coarser grained sandstone bodies, in contrast to the fine-grained material that represents the majority of the fill. In map view, these high-amplitude events are axially elongated, dip-trending bodies that were deposited laterally adjacent to one another. In the deepest parts of the ARCO 1 well, stratigraphically below their original objective, approximately 50 net ft of oil-saturated but very low-permeability silt and shale were encountered. Examination of the well location on seismic data indicates that the ARCO 1 well was drilledmore » into in the canyon flank, updip from and laterally adjacent to the high-amplitude events. The interpretation is that the low permeability oil saturated sections seen in the ARCO 1 well is representative of the depositional transition into the seal facies. Therefore, the highest amplitude events located downdip of the ARCO 1 well are thought to represent stratigraphically trapped hydrocarbons reservoired within canyon-fill sands, an interpretation supported by positive amplitude vs. offset analysis results.« less

Teaching middle managers to think like executives

Reports on the new case‐oriented system of management development being used by the Presidents of ARCO Oil and Gas in an attempt to improve the ability of middle management to add value to an organization. Examines case and organizational analysis as deployed in the Middle Management Seminar, and the formulation of The Personal Action Plan. Considers presidential feedback on the programme′s prospects.

Application of low‐voltage scanning electron microscopy on a low‐vapor pressure and high‐viscosity liquid phase: An experimental study of crude oil‐wet samples

ScanningVolume 11, Issue 5 p. 219-221 Short NoteFree to Read Application of low-voltage scanning electron microscopy on a low-vapor pressure and high-viscosity liquid phase: An experimental study of crude oil-wet samples L.-C. Liang, Corresponding Author L.-C. Liang ARCO Oil and Gas Company, Plano, Texas, USALong-Cheng Liang ARCO Oil and Gas Company 2300 West Plano Parkway Plano, TX 75075 USASearch for more papers by this author L.-C. Liang, Corresponding Author L.-C. Liang ARCO Oil and Gas Company, Plano, Texas, USALong-Cheng Liang ARCO Oil and Gas Company 2300 West Plano Parkway Plano, TX 75075 USASearch for more papers by this author First published: 1989 https://doi.org/10.1002/sca.4950110504AboutPDF ToolsRequest permissionExport citationAdd to favoritesTrack citation ShareShare Give accessShare full text accessShare full-text accessPlease review our Terms and Conditions of Use and check box below to share full-text version of article.I have read and accept the Wiley Online Library Terms and Conditions of UseShareable LinkUse the link below to share a full-text version of this article with your friends and colleagues. Learn more.Copy URL Share a linkShare onFacebookTwitterLinked InRedditWechat Volume11, Issue51989Pages 219-221 RelatedInformation

Qualification and Use of a Mill-Premium Connection in a Geopressured Gulf of Mexico Application

Summary Qualification tests were conducted on a new connection for use in a geopressured Gulf of Mexico application. Possible compaction of an unconsolidated reservoir under pressure decline made postyield axial strains in the well casings possible. Strain-limit tests were conducted in addition to conventional tests for structural load capacity and gas/thermal-cycle sealing. Unique approaches were also taken on the thread compound for the connection to alleviate the "trapped-dope" phenomenon. The connection was a mill-premium connection with tapered, interference-fit threads, a metal-to-metal seal, and a teflon seal ring. Testing and use of the connection were successful, including the unique strain-limit and thread-compound work. This paper describes project background, test design and execution, and field use of the connection. Introduction Extensive qualification testing was conducted on a new connection for use in a geopressured Gulf of Mexico application. The only previous use of the connection was a geothermal application, so this was the first high-pressure use. Because of expected compaction of the unconsolidated reservoir under pressure decline from production, subsidence of the pay sands could induce postyield strains in the well casings. For this reason, strain-limit tests were added to more conventional tests for structural load capacity (typical for drilling strings) and gas/thermal-cycle tests (typical for production strings). In addition to the wider scope of the tests, unique approaches were taken regarding the thread compound used on the connection to avoid the trapped-dope phenomenon. The connection chosen for the qualification effort was a mill-premium connection, based on tapered, interference-fit threads with a metal-to-metal seal and a teflon seal ring. Testing and use of the connection were very successful, including the unique strain-limit and thread-compound work. This paper describes the project background, test design and execution, and field use of the connection, and should be of interest to engineers facing similar qualification tasks or selecting connections on a more simplified basis. Project Background Platform Development Project. In Spring 1985, Arco Oil and Gas Co. began procurement procedures on development drilling tangibles for a recently discovered field offshore Louisiana. The planned development for the field involved eight wells at about 12,000 ft [3660 m] total vertical depth (TVD). As shown in Fig. 1, the well programs called for 24-in. [61-cm] conductor, 18 5/8-in. [47-cm] surface, 13 3/8-in. [34-cm] protective, 9 5/8-in. [24.4-cm] protective, and 7-in. [17.8-cm] production casings. Estimated well conditions included shut-in bottomhole pressures of 9,600 psi [66.2 MPa] and bottomhole temperatures of 200 deg. F [93 deg. C]. Surface pressures would vary from 7,300 psi [50.3 MPa] flowing to 8,200 psi [56.5 MPa] shut in with flowing temperatures up to 160 deg. F [71 deg. C]. With setting depths for the 9 5/8-in. [24.4-cm] protective casing near 12,500 ft [3810 m] measured depth and for the 7-in. [17.8-cm] production casing near 13,500 ft [4115 m] measured depth, total footage for the eight-well development project was 100,000 ft [30 480 m] for the 9 5/8-in. [24.4-cm], 53.50-lbf/ft [780.8-N/m] P-110 and 108,000 ft [32 918 m] for the 7-in. [17.8-cm], 35-lbf/ft [510.8-N/m] P-110. Procuring tubulars on a project basis maximized economic leverage and discounts with the product suppliers.

Minimum Area Rig Concept Update: H and P 101 Modifications and First Infield Move

Summary. The minimum area rig concept (MARC) is a cost-effective alternative to the typical self-contained platform rig (SCPR). Helmerich and Payne (H and P) built the first MARC rig, H and P 101, to drill and to work over wells up to 16,000 ft [4877 m] measured depth. This rig began operation in May 1983 in the Gulf of Mexico at Arco Oil and Gas Co.'s South Pass Block 61 field and has undergone one infield move. Since the rig's initial mobilization, several rig modifications have been added to increase storage area, to promote safety, to provide a more efficient drilling/workover rig, and to reduce overall move time. This paper describes the modifications and recaps the rig's first move. This will provide further insight into the MARC rig and show the benefits of the MARC design in relation to a move. Introduction H and P Rig 101 was designed, contracted, and built to work in the South Pass 61 field. The rig was mobilized initially in May 1983 and has proved to be the most efficient offshore drilling/workover rig in service in our Southeastern Dist. A savings of $1.4 million/yr over an SCPR has been realized as a result of lower day rate (lower initial investment) and mobilization/demobilization costs. The MARC design was needed in the operator's offshore environment to facilitate drilling and workover operations on producing platforms. All the platforms in the South Pass Block 61 field have production equipment on the drill deck (i.e., quarters and compressors), leaving approximately 75 % of the deck for a drilling/workover rig. Consequently, a rig was needed that would fit in the limited space but would still have the capabilities to drill and to work over up to 16,000-ft [4877-m] directional wells. (See Figs. 1 and 2 for original rig layout.) Economics was also an important criterion considered in the MARC design. The MARC rig design was planned to service the operator's platforms easily, yet eliminate an expensive derrick barge for each move. As a result, the "leapfrog" crane concept was used, whereby the crane that offloads the rig from the barges to the platform serves as the rig crane through the next move. H and P Rig 101 was mobilized initially on South Pass Block 60 Platform D, performed 12 workovers, and drilled eight wells. Modifications to the rig have been made, and the rig has moved to other platforms. This paper documents the modifications and the first move. Rig Modifications The deficiencies with the original MARC design evolved around the limited available space and resultant space use. Modifications were proposed to add badly needed storage area and to improve the overall efficiency of drilling, workover, and moving operations. We contracted IMI Engineering, the firm that originally designed the rig, to perform a third-party engineering evaluation of what improvements could be made without exceeding existing load limits. We requested that IMI submit a turnkey bid for construction and supervision through installation of the approved modifications. Construction-grade drawings were made, and after a final meeting, work on the modifications began. The following is a description of each modification. Drawworks/Wireline Shed. One of the most apparent areas in need of improvement was a permanent position for an electrical wireline unit. The skid-mounted units being used were costing the rig up- and downtime, and damages were occurring during transport and handling. Also, covered storage was limited on the rig. As a result, a drawworks/wireline shed was designed to fit on the back porch of the rig floor. This shed incorporated a permanent position for an electrical wireline unit, a covered storage area in a place that was previously open to the weather, and a mast stand that is needed to rig up or down the derrick. The shed was welded to the back porch. so it did not add a lift during moves. The wireline unit was installed on top of the shed and is out of the way during normal operations (Fig. 3). Besides supplying a covered storage area for small tools, the shed protects the previously open rig floor from weather. Mud Logger Floor. The permanent mud-logging unit consumed too much space in its original location, the "hole" on the drill deck between the pipe rack and rig structures. It was left rigged up when possible, regardless of whether completion or workover operations were in progress. This was taking up valuable equipment storage space, however, especially during gravel packs, and was unsafe (approximately 50% of the crane lifts passed over the unit). JPT P. 340^

Dominant Processes In In-Situ Combustion of Light Oil Reservoirs

Abstract To interpret and optimize field performance of in-situ combustion, dominant chemical and physical mechanisms comprising the displacement process must be understood, and the influence of reservoir characteristics and operating procedures in determining swept areas of the reservoir must be established. This paper addresses important aspects of these factors via a numerical simulation study. Vaporization of the oil, changes in oil volatility due to coking, and changes in oil properties due to low temperature oxidation are shown to have considerable impact and need to be adequately modelled. The extent of fingering of the burned region due to high permeability layers and the dependence of fingering on vertical permeability are investigated. Various operating procedures that are evaluated include: reinjection of exhaust gases procedures that are evaluated include: reinjection of exhaust gases rich in carbon dioxide, simultaneous water-oxygen injection to control override, post-burn waterflooding, and selection of well spacing. Introduction Prediction of in-situ combustion field performance requires: Prediction of in-situ combustion field performance requires:understanding the relative importance of the constitutive chemical and physical processes that determine oil displacement in those areas of the reservoir that are swept, andmarket opportunities for the application of energy technologies and systems. understanding how fluid flow and reservoir characteristics determine swept volume. Although researchers have derived much information from one-dimensional combustion tube studies, results cannot be scaled up to predict field performance. Due to differences in length and time scales and difficulty in reproducing reservoir conditions, the relative importance of various mechanisms in a combustion tube is not the same as in a reservoir. Although bench-scale experiments have been used to investigate individual processes known to occur, the extent to which each process can affect field results, such as oil produced or oxygen required, remains to be determined. Although numerous field studies have been performed, results are far from comprehensive, reservoir peculiarities cloud results, and extrapolation of results to other fields is difficult. Numerical simulation programs have been developed to help understand and predict in situ combustion performance. The cost of running a predict in situ combustion performance. The cost of running a simulator that contains all applicable physics, however, is prohibitive, and much required experimental input is unavailable. prohibitive, and much required experimental input is unavailable. The goal of the present investigation is to determine which physical, chemical, and fluid flow processes can significantly physical, chemical, and fluid flow processes can significantly affect oil production, oxygen consumption, and time required for in-situ combustion. Such information will facilitate execution and interpretation of field projects and help determine which phenomena should be included in in-situ combustion reservoir simulators and/or deserve additional investigation. To do this, oil production via in-situ combustion was phenomenologically examined to determine which processes are occurring. To determine the relative importance of these processes, simulations have been performed, using ARCO Oil and Gas Company's in-situ combustion reservoir simulator, in which comparisons have been made between predicted field performance with and without the effects of each process. Processes addressed include vaporization of the oil, coking, low Processes addressed include vaporization of the oil, coking, low temperature oxidation, exhaust gas re-injection, gas override and possible control via water injection, and instabilities due to possible control via water injection, and instabilities due to vertical variations in horizontal permeability. Using this approach, an improved understanding of in-situ combustion has emerged. The current findings are for a light oil subjected to high oxygen concentration injection gases; generalization of the results, however, is expected to be straightforward.

New research vessels

Two “new” ocean‐going research vessels operated by the Scripps Institution of Oceanography and the National Science Foundation (NSF) will soon begin full‐time scientific duties off the coast of California and in the Antarctic, respectively. The 37.5‐m Scripps vessel, named Robert Gordon Sprout in honor of the ex‐president of the University of California, replaces the smaller ship Ellen B. Scripps, which had served the institution since 1965. The new ship is a slightly modified Gulf Coast workboat. Under the name of Midnight Alaskan, it had been used for high‐resolution geophysical surveys in American and Latin American waters by such firms as Arco Oil & Gas, Exxon, Pennzoil, and Racal‐Decca before its purchase by Scripps from a Lousiana chartering firm last summer.

Waterflooding the Grayburg Formation on the J.L. Johnson AB Lease: Experience in the Johnson Field

The Grayburg formation in the Johnson field, Ector County, Texas, is a more complex reservoir than originally believed. Poor response from waterflooding the J. L. Johnson ''AB'' lease with 40-acre five-spots led to development with 20-acre line-drive patterns. This caused a substantial production increase. Infill drilling has led to the discovery of random, anhydritefilled sections which act as barriers to flow. They are probably interconnected and may be the cause of poor response to injection on wide spacing. Anhydrite barriers may exist both in other parts of the Johnson field and in surrounding fields. These barriers could play an important role in determining how other waterfloods are designed.

Langley Deep Field, Discovery and Interpretation: ABSTRACT

In May 1978, ARCO Oil and Gas Co. completed the Langley Deep Unit 1 well in Lea County, New Mexico, discovering a deep gas field with production from two horizons. The discovery well produces gas from a northwest-southeast-trending anticline that has a reverse fault at the Ellenburger formation on the northeast flank of the structure. This reverse fault, possibly persistent to the base of the Wolfcamp Formation, generated an anticlinal feature in the upthrown block at the Devonian level. The fault itself is the trap at the Ellenburger formation. Major seismic evaluation of the eastern flank of the Delaware basin had proceeded for 10 years prior to the discovery of the Langley Deep field. The first major seismic group shoot, conducted in 1968, started on the Central Basin platform and proceeded into the Delaware basin. These seismic records had good, continuous, shallow reflectors. Deeper reflectors were present only on the Central Basin platform or in the deeper part of the Delaware basin but not on the eastern flank of the basin. By changing the field acquisition parameters and later the processing techniques, ARCO Oil and Gas Co. was able to improve the quality of the data and to identify continuous reflectors from the Delaware basin up onto the Central Basin platform, at least at the Devonian level. These improved seismic ata delineated an anticlinal feature with an associated fault trap that is the Langley Deep field. Since the discovery of the Langley Deep field in 1978, a new geologic interpretation has been proposed for the eastern rim of the Delaware basin. A major conclusion, based on seismic control, the well control from this field, and on subsurface control throughout southern Lea County, New Mexico, is that a strike-slip fault was activated during the Late Pennsylvanian and Early Permian and caused deformation resulting in the formation of the Langley Deep structure. End_of_Article - Last_Page 116------------

Petrologic evolution and paleogeography of the Late Cretaceous Nanaimo Basin, Washington and British Columbia: Implications for Cretaceous tectonics

Research Article| July 01, 1984 Petrologic evolution and paleogeography of the Late Cretaceous Nanaimo Basin, Washington and British Columbia: Implications for Cretaceous tectonics J. A. PACHT J. A. PACHT 1E&PR Geological Research Group, ARCO Oil and Gas Co., P.O. Box 2819, Dallas, Texas 75221 Search for other works by this author on: GSW Google Scholar GSA Bulletin (1984) 95 (7): 766–778. https://doi.org/10.1130/0016-7606(1984)95<766:PEAPOT>2.0.CO;2 Article history first online: 01 Jun 2017 Cite View This Citation Add to Citation Manager Share Icon Share Facebook Twitter LinkedIn MailTo Tools Icon Tools Get Permissions Search Site Citation J. A. PACHT; Petrologic evolution and paleogeography of the Late Cretaceous Nanaimo Basin, Washington and British Columbia: Implications for Cretaceous tectonics. GSA Bulletin 1984;; 95 (7): 766–778. doi: https://doi.org/10.1130/0016-7606(1984)95<766:PEAPOT>2.0.CO;2 Download citation file: Ris (Zotero) Refmanager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex toolbar search Search Dropdown Menu toolbar search search input Search input auto suggest filter your search All ContentBy SocietyGSA Bulletin Search Advanced Search Abstract Systematic variations in sandstone petrofacies of the Upper Cretaceous Nanaimo Group are related to basin evolution and uplift of surrounding tectonic provinces. A subaerially exposed horst partially separated southern and northeastern portions of the Nanaimo Basin. Volcaniclastic and arkosic sediment was derived from this horst. The horst subsided below wave base during very early evolution of the Nanaimo Basin, but it controlled sediment dispersal throughout basin development.Lower units of the Nanaimo Group, in the southern Nanaimo Basin, are chert-rich and were derived largely from terranes of the San Juan Islands and North Cascades. Basaltic and plutonic debris from the Insular Belt was deposited into the northwestern Nanaimo Basin during early basin development. Minor deposition of arkosic debris from the Coastal Plutonic Belt also occurred.Upper units of the Nanaimo Group contain abundant plagioclase-rich sediment derived from the Coastal Plutonic Belt. Rocks along the southeastern margin of the basin, however, reflect continued sedimentation from terranes of the San Juan Islands and North Cascades. Arkosic and dacitic debris from Insular Belt sources is recognized in the northwestern Nanaimo Basin.The Nanaimo Basin may have developed as a pull-apart basin within a broad zone of normal and transcurrent faulting in response to oblique convergence or transform faulting between the Kula(?) plate and the Pacific margin of Washington and British Columbia. This content is PDF only. Please click on the PDF icon to access. First Page Preview Close Modal You do not have access to this content, please speak to your institutional administrator if you feel you should have access.

Case History of Langley Deep Field in Lea County, New Mexico: ABSTRACT

In May 1978, ARCO Oil and Gas Co. completed the Langley Deep Unit 1 well in Lea County, New Mexico, discovering a deep gas field with production from 2 horizons. The discovery well produces gas from a northwest-southeast trending anticline that has a reverse fault at the Ellenburger formation on the northeast flank of the structure. This reverse fault generated an anticlinal feature in the upthrown block on the east flank of the Delaware basin that is the reservoir for the Langley Deep field Devonian strata, and the fault is the possible trap at the Ellenburger formation. This discovery was the result of an ongoing seismic program that started with a regional group shoot in 1968 on the Central Basin platform and the Delaware basin in Lea County, New Mexico. This survey obtained data that has at best only short discontinuous reflectors in the present area of interest. It could be used only to obtain dips of unknown geologic horizons. ARCO Oil and Gas Co. has been in additional group shoots or has acquired seismic data in each year from 1973 through 1981 in the Delaware basin and Central Basin platform of New Mexico. Each vintage is an improvement in the quality of the section in terms of both the continuity of events and resolution of events. New acquisition and processing techniques contribute to the enhancement of the data. Even though better record s ctions are obtained with each successive vintage, the improvement is limited in each case. The most improvement in record section quality is between the data acquired in 1968 and 1973. The exploration play developed when data acquired in 1973 was reprocessed in 1975 including diffraction migration, which clearly demonstrated the presence of the critical east dip on Devonian and older formations. Subsequent seismic programs define the limits of the closure. The 1978 discovery well confirmed the existence of the seismic structure. Seven wells have been drilled to date on the Langley Deep seismic feature. Six wells have been completed and are producing gas from Devonian and Ellenburger formations. The seventh well had shows but is considered noncommercial. The only other deep well on the structure was drilled in 1962 to Conoco Inc. to the Ellenburger formation on the northern end of the Langley Deep feature, but was over 500 ft (150 m) lower at the Devonian formation w en compared with the shallowest penetrations of these formations on the Langley Deep structure. The success of finding the Langley Deep field is due to recognizing that the potential for finding reservoirs exists in the no-data zones on seismic. By continually investigating and searching for the causes of the no-data zones, new and improved acquisition and processing techniques revealed a gas field that would never have been found if exploration stopped after the initial efforts to define the subsurface. The continued efforts to specify the subsurface along the western edge of the Central Basin platform and eastern edge of the Delaware basin not only resulted in the discovery of the Langley Deep field, but also renewed interest of the majors and independents in this area. Conoco Inc., ARCO Oil and Gas Co., and Shell Oil Co. have drilled additional deep End_Page 482------------------------------ gas producing wells on similar features that are on trend with and to the south of the Langley Deep field. Thus, the effort of improving the quality of seismic reflections not only led to the discovery of the Langley Deep field but also generated the impetus that discovered additional reserves on other features along the same general trend. End_of_Article - Last_Page 483------------

Numerical Simulation of the Effect of Critical Gas Saturation and Other Parameters on the Productivity of Methane From Geopressured Aquifers

Summary A numerical simulation study has shown that critical gas saturation is one of the most significant parameters that controls the productivity of methane from geopressured aquifers. Ultimate fluid production from such reservoirs is restricted by insufficient gas in solution to maintain the reservoir pressure. Introduction Geopressured aquifers in the U.S. gulf coast area have received wide publicity as a possible major source of methane. Geological and geophysical studies have indicated suitable reservoirs over a wide area of southern Texas and Louisiana. The economics of methane recovery from geopressured aquifers has been questioned by studies such as that by Doscher et al. A detailed reservoir modeling study was conducted to predict performance characteristics of these reservoirs. In particular, sensitivity studies were made to determine effects of various parameters, that might enhance the economic production of methane from such reservoirs. Physical Properties of the Reservoir and the Brine The geopressured brine studied in this work is saturated with methane at 11,000 psia (75 840 kPa) and 240 degrees F (116 degrees C). The PV properties of the brine are shown in Figs. 1 through 4. The solubility of methane in pure water is a function of both pressure and temperature. Over the pressure range of geopressured reservoirs. the solubility increases with temperature. For the temperature range assumed in this study, a maximum solubility of 34 scf/STB (6.05 std m3 /stock-tank m3) in the 30,000-ppm brine is expected. The available FVF data for water were extrapolated to the required higher pressure range. For the studied range of pressures, Bw varies from 1.037 to 1.045 RB/STB (res m3/stock-tank m3) (Figs. 2 and 3). FVF increases only slightly with gas saturation (Fig. 3). The viscosity data used for brine 4 are shown in Fig. 4. The effect of dissolved hydrocarbon gases in water is not known, but it is not believed significant because of the very low solubility of methane. One significant change was made in the assumed properties of the reservoir since the conclusion of the earlier study; the compressibility was reduced by a factor of two, to 5 × 10 -6 psi -1 (7.3 × 10 -7 kPa -1). This lower value was chosen because, as Geerstma concluded, the effective value of compressibility should be of the order of one-half that measured in the laboratory under triaxial loading. Although no laboratory data on the compressibility of cores from geopressured reservoirs are available in the literature, 1 0 × 10 -11 psi 1 (1.5 × 10 - 6 kPa is the highest value for most reported laboratory measurements. Description of the Reservoir Model The numerical model used is essentially the four-component model developed by ARCO Oil and Gas Co. and has been described elsewhere. The object code was loaned to the U.S. of Southern California. Through the input data, various options as to the dimensional configuration of the reservoir and the use of either a four-component or a black-oil system could be exercised. A 9×9×1 areal grid was used to simulate the performance of a typical well draining a 40-sq mile (103.6-km2 ) area. The number of phases was scaled down to a gas phase (methane) and a liquid phase (brine) by manipulation of the input data. This was accomplished by the adjustment of the relative permeabilities, capillary pressure curves, and the PVT data such that the oil phase and the water phase had identical properties. JPT P. 1880^

Application of Exploration Play-Analysis Techniques to the Assessment of Conventional Petroleum Resources by the USGS

Summary Data from 40 offshore oil and gas production platforms in the Gulf of Mexico have been analyzed for bias. The significant biases found were deemed the result of an optimistic estimation process. Computer modeling shows these biases to have an effect on a company's operations. Several possible causes of and cures for the biases are suggested. Introduction To the layman, petroleum engineering may appear to be an exact discipline. The numerical result of a long series of calculations mistakenly can be regarded as some sort of true value. The engineer, on the other hand, knows that the answers he arrives at are, for the most part, estimates: thus, there is always uncertainty as to their accuracy. What follows is an examination of a large group of estimates (approximately 640) connected with the installation of 40 oil and gas platforms in the Gulf of Mexico. The estimates have been compared with actual values when possible (such as with the time required to install the platform) or with the most recent and presumably best estimate (such as with the total oil reserves recoverable from a platform). Several statistical methods have been applied to the data in an attempt to answer several questions for each of the 16 variables and for the body of data: Are the data biased? What is the magnitude of the bias? Are the biases statistically significant? How do the biases affect the projects' performances? How do they affect the company's performance? What might be the causes of these biases? What can be done to minimize them and their effect on the company? This study is based on an engineer's degree thesis, which in turn was based on data released by ARCO Oil and Gas Co., South Texas Dist., Offshore Section. Theory and Data Analysis While much has been written in engineering and management journals regarding the uncertainties present in decision making, little has been reported on the presence of consistent misestimation (bias). Even less has been written on the measurement and interpretation of observed bias. Tversky and Kahneman describe the phenomenon of overestimation and show how biases can be incorporated into intuitive decision processes. They deal with the problem from a decision science point of view. Uman et al. provide a very informative case study of pre- and post drilling estimates of oil and gas reserves. These estimates were made by the USGS for offshore dulling tracts. While the authors found that the reserves estimates could be considered accurate only to plus or minus an order of magnitude (0.1 x predrilling estimate less than post drilling determination less than 10 x predrilling estimate), they found no bias in the majority (80%) of data sets (as grouped by Outer Continental Shelf sale numbers). The data examined here were examined concurrently and reported by Franzen et al., and the reader is referred to their paper for additional analyses and conclusions. This study is based on data gathered from Gulf of Mexico production platform files. These data have been used by the Conoco Inc./ARCO Oil and Gas Co./Getty Oil Co./Cities Service Co. consortium in the evaluation and planning of these platforms. Forty platform projects were chosen as the source of the data set. To be included in this study, the project had to have been initiated within the last 15 years and had to be completed or nearly completed by the time the data were gathered. To evaluate these variables for bias, "before" values estimated for the initial project proposal, and "after" values, the actual or most recent estimates of the variables' values, were gathered for each of the 16 variables and for each of the 40 platforms. JPT P. 433^

Sheep Mountain CO2 Production Facilities - A Conceptual Design

This paper discusses the potential supply of CO2 for enhanced recovery projects from the natural CO2 reservoir at Sheep Mountain, Huerfano projects from the natural CO2 reservoir at Sheep Mountain, Huerfano County, CO. Producing well characteristics are examined, and a conceptual process is discussed for separation of water, dehydration, compression, and transportation of 300 MMscf/D of CO2 from Colorado to Texas. Introduction Carbon dioxide (CO2) enhanced recovery projects potentially could recover up to 40% of all oil produced by potentially could recover up to 40% of all oil produced by enhanced recovery methods. CO2 supply is a critical factor in the ability to undertake the scope of available projects. The major sources of supply include power projects. The major sources of supply include power plant stack gas, future coal gasification plants, and plant stack gas, future coal gasification plants, and natural deposits. Although power and coal gasification plants eventually may be important sources, natural plants eventually may be important sources, natural deposits likely will be the first source to be developed.ARCO Oil and Gas Co. began studies of a natural CO2 reservoir at Sheep Mountain in Huerfano County, CO, in 1972. These studies resulted in lease of private, state, and federal lands and the formation of two development units, Sheep Mountain Unit and Dike Mountain Unit (Fig. 1). Sixteen wells within these units have delineated a deposit of sufficient size to warrant a pipeline study. Given sufficient incentive for enhanced oil recovery, ARCO Oil and Gas Co. could build a 20-in. pipeline 420 miles to the Permian basin to deliver 300 MMscf/D. The proposed route shown in Fig. 2 terminates at the Wasson (San Andres) and Seminole (San Andres) fields located in Yoakum and Gaines counties, TX. Pipeline Pipeline The pipeline would begin in the northwestern portion of Sheep Mountain Unit at an elevation of 8,000 ft and continue southeast near Trinidad, CO, where it would drop to an elevation of 5,400 ft. The line would climb to an elevation of 8,250 ft east of Raton Pass before continuing southeastward across New Mexico and into Texas to the Seminole field at an elevation of 3,400 ft.The pipeline would operate as a liquid-filled system requiring sufficient pressure throughout the line to prevent two-phase (gas/liquid) occurrence and an input prevent two-phase (gas/liquid) occurrence and an input pressure exceeding 1,200 psig. CO2 density at various pressure exceeding 1,200 psig. CO2 density at various pipeline operating conditions can vary from 44 to almost pipeline operating conditions can vary from 44 to almost 60 lbm/cu ft; therefore, the differences in elevation involve significant head changes. Two-phase conditions would be approached at the maximum design rate of 300 MMscf/D where the line rises to 8,250 ft, resulting in the lowest line pressure of approximately 950 psig. Two-phase conditions would be approached more closely in late summer as the flowing temperature peaks, perhaps approaching 75 degrees F. The 8,250-ft location also would be critical to winter operating conditions because of the reduced ability of the CO2 to hold water at low temperature and pressure. One criterion for pipeline corrosion control is for the CO2 to have a water content less than 60% of saturation. Thus, the 8,250-ft elevation mountain crossing establishes the required input line pressure and the degree of dehydration required of the producing equipment.Desired pipeline delivery pressure is approximately 2,000 psig, which is sufficient for field distribution and injection control. The pipeline is sized to facilitate this delivery pressure at 300 MMscf/D without booster compression along the line. JPT P. 1462