Major Sands Research Articles

Low-Resistivity/Low-Contrast Reservoirs Increase Production in Offshore Brownfield

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202331, “Unlocking the Hidden Oil: How Low-Resistivity, Low‑Contrast Reservoirs Contributed to 800 BOPD of Production in a 30‑Year‑Old Offshore Brownfield,” by Su Li Tham, SPE, Kwang Chian Chiew, and Hamed Hassani, Petronas, et al. The paper has not been peer reviewed. Production-enhancement opportunities in 30-year-old Field D in Balingian province, offshore Sarawak, are dwindling. An in-house evaluation tool, resolution enhanced modeling (REM), was developed to evaluate and characterize thin beds or laminations. These low-resistivity/low-contrast (LR/LC) sands are commonly bypassed because conventional logging tools cannot resolve their true parametric values and the apparent log responses across these zones appeared as shaly sand. By running REM across these intervals, the properties of the thin sands could be characterized properly, improving the net pay and economics of perforating and producing these reservoirs. Introduction The major reservoirs of Field D were deposited in a fluvial environment, resulting in channel sands, and are mainly under solution gas drive with weak aquifer and large gas-cap drive. The major sands generally are well-developed, including the implementation of water injection as a secondary recovery method in 2016 and perforation of remaining behind-casing opportunities across the field. As the field enters its later life, attention has been shifted to minor reservoirs in a final effort to extract remaining oil from wells before abandonment. In the case of Field D, the focus is on the LR/LC reservoirs (Fig. 1). These reservoirs mostly are shaly sands and are localized because of their depositional environment of mouth bars and crevasses. There are exceptions, however, as observed in Well A3-S and Well C6, where the reservoirs are clean sands with a thickness of 5–10 ft; these wells likely have penetrated the center of a mouth bar or crevasse. These LR/LC plays can be detected only by high-resolution logs or core photography. Consequently, LR/LC reservoirs are often overlooked because their properties and hydrocarbon saturation are underestimated, thereby placing them below the cutoff as pay zones. Thus, reservoir characterization and subsequent estimation of reserves remain a challenge in maturing LR/LC perforation proposals.

Mineral distribution and provenance of heavy mineral sands (zircon, ilmenite, rutile) deposits from the NW Murray Basin, far western NSW, Australia

There is significant economic interest in the Murray Basin of southeastern Australia as it is proving to be a major heavy mineral sands (HMS) province that will be one of Australia’s major source for production of rutile, zircon and ilmenite. The distribution and provenance of HMS resources in the Murray Basin is poorly understood because of its huge size, limited exploration and the complex depositional, structural and weathering mechanisms in their development. In this paper, we focus on the Copi North and Magic deposits some 130–180 km south of Broken Hill, NSW. The heavy mineral assemblages of the Copi North and Magic deposits are very similar, with the main economic minerals being ilmenite, leucoxene, pseudorutile, rutile and zircon. Intensive fracturing and brecciation are identified in many samples and are inferred to have been initially caused by multi-stage deformational processes associated with metamorphism and then further developed through alluvial and eolian transportation. Both deposits are classified as ‘medium sands, symmetrical, mesokurtic and moderately well-sorted’. The majority of economic minerals are of low to medium sphericity and subrounded, along with abundant polished eolian quartz grains. The Copi North deposit has coarser and more poorly sorted sediments with higher HMS grades and magnetics content than the Magic deposit, reflecting a higher energy depositional environment. The main source for the HMS for the Copi North and Magic deposits is largely ascribed to the Broken Hill Block. Previous studies have shown that the Broken Hill orebody underwent substantial sub-aerial weathering over hundreds of millions of years. In addition, the complex metamorphic events experienced by the Broken Hill Block were capable of forming the broad series of minerals identified within the Copi North and Magic deposits. The HMS were believed to have been transported through paleovalleys near the Mulculca Fault in a southeast direction representing a feeder system into the NW Murray Basin. Both deposits feature a relatively linear geometry (roughly parallel to the strike of the paleoshoreline), with high HMS grades, modest tonnages, and coarser sediments when compared to WIM-style offshore deposits. Compared to other strandline HMS deposits of the Murray Basin, they are smaller in size although have similar high grades of 3.7–6.9% THM and similar proportions of the HMS assemblage of ilmenite, leucoxene, rutile and zircon. Deposits of similar size and grade are likely to occur throughout the northern part of the Murray Basin.KEY POINTSBoth the Copi North and Magic deposits contain similar mineral assemblages with the provenance of the heavy minerals ascribed to the Broken Hill Block.A relatively high energy inshore environment is inferred for the Copi North deposit while a lower energy environment associated with either a foreshore or backshore environment is inferred for the Magic deposit.Deposits of similar mineralogy, grades and size are likely to occur elsewhere throughout the northern Murray Basin.

Sedimentary Characteristics and Lithological Trap Identification of Distant Braided Delta Deposits: A Case on Upper Cretaceous Yogou Formation of Termit Basin, Niger

Lithological trap identification in thin sand and thick shale layers is still a challenge for hydrocarbon exploration. Based on the high-resolution sequence stratigraphy theory and the establishment of high resolution sequence stratigraphy framework with seismic-well tie, the dynamic deposition process of braided river delta sands on late Cretaceous Yogou formation has been analyzed on 62 wells in passive rift Termit basin with multi-stages depressions and reversals. (1) Six kinds of sedimentary microfacies and three major reservoir sands with multi-stages stacking and lateral migration are in Yogou formation; (2) Based on Accommodation space/Sediments supply change and the deposition progress, sedimentary facies distribution in each member of YS3 sub-formation has been done according to sands thickness statistics of sedimentary micro-facies, narrow-time seismic attributes and slices analysis, multi-sources braided river delta depositional model has been concluded; (3) Based on source rock and caprock evaluation, with reservoir sands distribution and faults impact on Yogou formation of Termit basin, four types of traps, including structure-lithology, Structure-strata, stratigraphic and lithology are concluded. Traps influencing factors, i.e., structure geometry, sands distribution, paleotopography, stratigraphy cycling, sand/shale lateral connection, reservoir quality and so on, have different impacts on these traps, and different lithologic-stratigraphy traps have different exploration risks. Structure geometry and sands distribution are very important for the structure-lithology traps; structure geometry and paleotopography are the key factors in Structure-strata traps. Sands distribution and reservoir quality can be focused on lithology traps. Moreover, paleotopography and sand/shale lateral connection are significant on stratigraphic traps. Therefore, different hydrocarbon accumulation types of lithological traps have been established.

Geologic characteristics of deep water deposits and exploration discoveries in slope zones of fault lake basin: A case study of Paleogene Shahejie Formation in Banqiao-Qibei slope, Qikou sag, Bohai Bay Basin

Abstract Based on seismic, logging, formation testing, core and lab test data, this study analyzed the sequence division, facies features of deep water deposits and modes, development of large-scale gravity flow, reservoir physical properties and their main controlling factors, and proposed a classification standard and prediction method of favorable exploration areas in deep water area of the Bin1 oil layers of the lower sub-member of the first member of Paleogene Shahejie Formation in Banqiao-Qibei slope zone of Qikou sag, Bohai Bay Basin. The Bin1 oil layers can be divided into three fifth-order sequences, each less than 100 m thick; a set of gravity flow deposits were formed under deep water background in the slope zone, which contains sedimentary micro-facies such as main channel, distributary channel, channel margin, inter-channel mudstone, and turbidite sand sheet in areas without channels, and, in space, has inherited and constructive development features of multistages. It is a sedimentary sequence of fan delta – distal subaqueous fan – deep lake, and every distal subaqueous fan formed by gravity flow can be divided into inner-, middle- and outer fans. The cross-facies transported sands which are sourced from higher-sand-content major sands of delta front can form high quality reservoirs with an average porosity of 15.1% and geometric average permeability of 5.1×10−3 μm2. The main channel and distributary channel of distal subaqueous fan are the most favorable exploration zones.

An Object in Motion Stays in Motion

What’s Ahead–From TWA’s Editor-in-Chief Being a young professional working in the oil and gas industry right now means learning a lot of things the tough way. Our business is changing rapidly, working to reflect the changing realities of a cyclical commodity, changes to environmental legislation, and increased technical rigor required to explore for and produce oil and gas. This means that for many young professionals, the required skill sets are changing quickly as is the need for certain expertise. I suspect many people have gone through some major career transitions in the last year, or at minimum, have association with individuals that have gone through one. The simple truth is that we all go through major transitions during the course of our life, whether it is at work or in our personal lives. Some transitions are memorable, others are noble, and some are regrettable, but all of them provide you with an opportunity to reflect, learn, and adapt. I can think of several major transitions that I have gone through in my life, and all of them have provided me with an opportunity to grow as a person. One of the more memorable ones was moving to Christina Lake, Alberta—located in the boreal forest of the Canadian North—where I lived for 18 months supporting the construction and commissioning of a major oil sands facility. The experience I gained on site was both rewarding and exhausting. We worked long hours, lived in an on-site camp (the baked goods always get you), and spent evenings catching up on current events. Fortunately, our camp had a great recreational center which allowed me to keep in shape and inhibit the weight gain that almost seems inevitable at such times. I made some great friends at the site and I would say that the experience was well worth it for my career development, helping me understand our business and later transfer to more subsurface-based roles. But there was also an impact on my personal life. I was separated from the ones I loved and lost touch with many people over the 18 months. In many respects, I put my life on hold during the time I was up there. Working in the field as a young engineer provides development opportunities that are hard to replicate elsewhere—seeing well and field operations in action, conducting inspections, troubleshooting on the fly, and most of all, working with field personnel who have a plethora of experiences and wisdom to share. I suspect that many readers have their own stories of career transitions in the field, office, or academia. I would encourage you to share stories of your career transitions on SPE platforms like SPEConnect or SPE social media sites for the benefit of other young professionals.

Cold Lake Borehole Mining

Abstract As part of an ongoing research and development effort, Imperial Oil has embarked on a program to develop new low cost in situ recovery technologies for oil sands as an alternative to cyclic steam stimulation. Oil such technology is borehole mining, which utilizes high pressure water jets to create a cavern in the formation and force the liberated bitumen to the surface through the annular space between the casing and the jetting string. This paper reviews the borehole mining concept and discusses the results of two field pilots conducted in 1990-and 1991 at Imperial Oil Resources' Cold Lake lease. It focusses on the behaviour of the oil sands matrix as the cavern is created and the performance of the hydraulic pumping system. It concludes that valuable knowledge has been gained with respect to design parameters for borehole mining, but that the process is unsuitable for producing the Cold Lake lease owing to poor mining efficiency. and instability of the shale roof of the cavern. Introduction The Cold Lake oil sands deposit in north-eastern Alberta contains over 40 billion cubic metres of bitumen (Figure 1). Imperial Oil currently operates several pilot and commercial oil sands production projects in this area. Bitumen is produced from a reservoir approximately 40 m in thickness at a depth of about 450 m. Total production from almost 1,800 experimental and commercial wells exceeds 14,000 m3 per day. Owing to the low energy state and high viscosity of bitumen at reservoir conditions, high pressure thermal methods are used at Cold Lake. The majority of Imperial's bitumen production is obtained using cyclic steam stimulation (CCS). However, to achieve higher recovery levels and profitability, Imperial Oil has embarked on an R&D program to develop lower cost alternatives to cyclic steam stimulation. While conducting a well repair program in early 1989, Imperial identified an alternate bitumen recovery process. A surface discharge of bitumen was discovered near an abandoned well at Cold Lake(1). The bitumen had been displaced up the abandoned hole by adjacent steaming operations. To plug the abandoned well, a relief well was drilled into the Clearwater Formation so that its bottom was within one metre of the existing well. A water jetting tool was lowered into the relief well to cut out a thin window in the casing and create a cavity to place cement. While jetting, large volumes of oil and sand accumulated in the return tank. The sand, bitumen and water were observed to separate as they flowed into the tank. Consequently, Imperial initiated a research program to explore FIGURE 1: Location of the four major cretaceous oil sands deposits in Alberta. Available In Full Paper. The potential of hydraulically mining oil sands as a more economical alternative to steam-based processes (Figure 2). Initially, physical model tests were conducted in the laboratory to visualize the mining process, followed by two small scale field pilots, conducted in 1990 and 1991. The purpose of this paper is to share the experience gained in executing those two field pilots.

Low Resistivity, Low Contrast Pays: Part II-Comparison of Examples from Southeast Asia and the Gulf Of Mexico: ABSTRACT

The Gulf of Mexico Basin (GOM) is the world's leading oil and gas producer from low resistivity, low contrast (LRLC) clastic intervals. Many GOM fields have had production from LRLC pays for more than 15 years and some for over 40 yrs. LRLC pay zones are being recognized more frequently now in other basins in the world, including southeast Asia. LRLC pays in southeast Asia have many similarities and some differences with the LRLC producing zones in the Gulf of Mexico Basin. The depositional environments containing LRLC pays in southeast Asia are (1) major regional and local marine transgressive sands, (2) deep-water sands, including levee-channel complexes, (3) deltaic channel and bar-front sands, and (4) shingled turbidites. LRLC pays in marine transgressive sands are more abundant in southeast Asia.

The Unare Lagoon: A Recent Example of Sequence Stratigraphic Control in Reservoir Patterns

The Unare lagoon constitutes a barred coastal lagoon formed during the Holocene transgression on a moderate wave energy, microtidal coast. An extensive surface sampling and core drill program has been carried out in the lagoon in order to develop a reservoir sedimentology and sequence stratigraphic model applicable to similar subsurface deposits. During the rapid Halocene sea level rise, more than 70 m of fluvial and delta plain sediments have aggraded behind the landward stepping coastal barrier. These sediments are truncated seaward by a transgressive wave ravinement surface, and are capped by widespread lagoonal muds which accumulated between 8300 and 7250 yBP. These muds constitute the Holocene Maximum Flooding Surface which preceded the onset of the post Holocene stillstand (c. 500[approximately] yBP), probably as a result of the high rate of sediment supply and the confined nature of the lagoon which acted as an efficient sediment trap. During the post Holocene stillstand, a fluvial-dominated delta has prograded across the lagoon and attained the coastal barrier. This delta constitutes a Highstand Systems Tract. The major reservoir sands comprise distributary channel meanderbelts and the transgressive barrier. The channels form sand ribbons 5-7 m thick, and up to 2 km wide. The barrier andmore » shoreface sands forms a strike-elongate deposits less than 5 m thick, up to 150-600 m wide, and 5-10 km long. The lagoonal facies of the Maximum Flooding Surface form a good reservoir seal overlying the aggrading transgressive fluvial and delta plain sands and muds.« less

Requirements For Major Oil Sands Mining Projects In Canada

Abstract Canadian conventional oil production is declining and any significant new conventional oil discoveries are located in remote, high cost frontier areas. Synthetic crude oil and bitumen production from the vast, known oil sands in Alberta could offset the decline. Although oil sands tend to be an expensive source of supply, their abundance and proximity to markets and industrial centres, as well as the significant potential for reducing production costs through technology improvements, make them attractive candidates for commercial development. For this to become reality, certain prerequisites need to be in place. Since oil sand leases were first granted in northeast Alberta in the late 1950s, only two major oil sands mining projects have been developed. Although several similar oil sands projects have been proposed since then, none hove proceeded much beyond the design stage. This paper reviews the development history and nature of oil sands mining projects, examines the requirements for major oil sands mining projects in Canada and the lessons leaned from previously proposed projects. The paper focusses on the impact that stakeholder commitment, appropriate fiscal terms, corporate financial strength, technology development and readiness, quality project development and operational excellence market understanding, resource quality and the balancing of resource development with environmental responsibility have on the feasibility of developing this resource. Introduction Over the next 15 years, production from Canada's conventional established oil reserves are expected to decline by up to 50%. New conventional oil discoveries in remote high-cost frontier areas and synthetic crude oil (SCO) and bitumen production from vast known oil sands resources could help to offset this decline. Already Alberta's oil sands are playing a significant role in meeting current energy demands. The combined bitumen and SCO production from these in situ and surface mining projects account for about 20% of Canada's daily oil production. Although the potential of the Athabasca oil sands has been known for more than 200 years, development of the resource did not begin until the 1930s. The first commercial project started production in 1967. In 1990, the Athabasca deposit, home of the Suncor Inc. and Syncrude Canada Ltd. commercial mining projects, was the source of 33 130 m3/d (208 390 bbl/d) of SCO or 13% of Canada's oil production. Since production from these two operations first began, six similar oil sands mining projects have been proposed. However, none have proceeded much beyond the design stage. The seventh project, the OSLO Project is in its pre-appropriation stage. The OSLO Project promises an additional 12 700 m3/d (80 000 bbl/d) of SCO or 5% of Canada's daily oil production. Development History Background Development of the Athabasca oil sands as a source of crude oil reserves has been slow. Research into the nature of the oil sands started in the early 1880s when researchers at the Geological Survey of Canada in Ottawa conducted an experiment to separate the bitumen from the sand using hot water.

Oil and Gas Developments in Western Canada in 1983

In 1983, petroleum industry activity in western Canada increased moderately after 2 successive poor years. This increase resulted from record activity in Saskatchewan, a shift from gas to oil exploration, renewed heavy oil development, and provincial government incentives. The total number of wells drilled increased by 7% to 6,755. Exploratory drilling decreased by 14% to 1,973 wells, but was more than offset by a 20% increase in development drilling to 4,782 wells. Exploratory success rate decreased to 62% from 65% in 1982, with 757 oil discoveries and only 461 gas discoveries. The development success rate increased slightly from 89% to 90%, with 3,393 oil completions and 913 gas completions. Exploratory drilling declined in all areas except Saskatchewan, whereas develop ent drilling increased in Saskatchewan, Manitoba, and the Northwest Territories-Arctic. Average well depths increased only in Alberta and Saskatchewan. Total revenue from land sales rose dramatically by 46% to $564 million (FOOTNOTE 4). Alberta land sale bonuses totaled $429 million, Saskatchewan $108 million, British Columbia $26 million, and Manitoba $1 million. Average price per hectare increased substantially in the 3 westernmost provinces, but decreased in Manitoba, exactly the opposite trend from 1982. Alberta exploratory and development drilling continued to decline, but still constituted 68% of western Canadian activity. Significant Devonian reef discoveries were made in the northern half of the province at Senex, Sawn Lake, Gift Lake (Nipisi), and Sturgeon Lake South, and major activity continued at Fenn-Big Valley (Rumsey), Carrot Creek, Valhalla, and Amigo-Shekilie. Two major oil sands projects, at Wolf Lake and Cold Lake, are underway. Two major oil sands projects, at Wolf Lake and Cold Lake, are underway. British Columbia recorded a major Mississippian oil find at Desan, the first major oil discovery in some time from this gas-prone province hard hit by gas surplus and marketing problems. Drilling activity in Saskatchewan soared to record levels and was the prime reason for t e overall increase in 1983 western Canadian activity. Exploratory and development drilling increased, and a total land sale record was established, most of which can be attributed to the Saskatchewan government's incentive program of royalty holidays. Manitoba activity continued its rejuvenation started at Waskada in 1980. Frontier activity was highlighted by a major oil and gas discovery at Itiyok in the Beaufort Sea, and by continued development of the shallow Norman Wells field on the Mackenzie River. Arctic Islands results were disappointing in that a development well at Cisco recovered less oil than anticipated due to structural complications. Major farmouts in the Beaufort Sea indicate continued activity in this area for years to come.

Administration Ofthe Bituminous Oil Sands Of Alberta

Abstract The exposed bituminous oil sands at Athabasca appear to have first received the attention of white settlers in 1719 when Henry Kelsey, one of Hudson's Bay Company's early Governors, observed a sample of bituminous sand brought to him at Fort York(1)). One of his Cree employees had travelled to the Athabasca valley and brought back a sample of "gum or pitch" taken from the river bank. Although the bituminous sands sample did not impress Kelsey in 1719, the resource was recognized as having enormous potential by others who followed close behind him. Extensive efforts have been made since then, by provincial, federal and industry interests to improve the understanding of the resource, establish its economic potential and ensure that it is developed in the best interests of Alberta and Canada. Early Disposition of Rights The first disposition of rights to develop the oil sands was made in 1901 by the Privy Council of Canada(2). Seven tracts comprising 12,725 acres along the Athabasca River at and north of Fort McMurray were patented for surface, asphalt and petroleum and natural gas. Regulations for the "Disposal of Tarsands, the property of the Crown", in that portion of Alberta lying north of Township 80 between the 4th and 5th Meridians were approved by Order of the Governor in Council in 1910. Tar sands were interpreted in the regulations as: " ...the sands and other material impregnated with tar, bitumen, petroleum, oil and other like substances found in deposits in the northerly portion of the Province of Alberta". Soon after this in 1912 the regulations were suspended and each application was considered on its own merits. In total some 21 leases were issued by the federal government. However, only four were in existence at the time of the transfer of the administration of the resources to the province in 1930. It appearsonly the leases held by Mr. Draper resulted in the construction of a plant and other significant operations prior to the transfer. However, in the late 1920s International Bitumen Company had commenced work at Bitumount leading to the major pilot extraction operations there in the 1930 to 1950 period. The first regulations issued by Alberta for the disposal of bituminous sands deposits, the property of the Crown in the Province of Alberta, were issued by order in 1930. Between 1930 and 1951 provincial agreements for development of the sands were entered into with companies and individuals including: Max Waite Ball, International Bitumen Company Limited, Abasand Oils Limited, and Lloyd Rogers Champion. Of this group of dispositions only that of Max Waite Ball of Denver, who also formed Abasand Oil, was continued. His work led later to the Great Canadian Oil Sands (now Suncor) development. A major bituminous sands conference was arranged by the Alberta government in September 1951 to study factors affecting bituminous sands development. In conjunction with the conference, Honourable N.E. Tanner, then Minister of Mines and Minerals, gave a: policy statement regarding prospecting permits and leases.

Lithofacies Control of Lignite Distribution and Ground-Water Quality, Wilcox Group (Eocene), East-Central Texas: ABSTRACT

Deep lignite resources (200-2,000 ft; 61-610 m) were evaluated regionally using 1,470 geophysical well logs to interpret lithofacies, lignite occurrence, and resistivity (water quality). The regional distribution of lithofacies indicates that in the region, the Wilcox Group is a fluvial-deltaic system. The primary fluvial system entered the Wilcox coastal plain west of Waco, Texas, trended southeast, and supplied a 75-mi (120-km) wide fluvial-deltaic system comparable in size to the Mississippi system. Lignites are most abundant in the Calvert Bluff Formation (upper Wilcox). Lower Calvert Bluff lignites are thickest and most extensive southwest of the Navasota River, whereas those of the upper Calvert Bluff are thickest northeast of the Brazos River. In the shallow subsurface, Calvert Bluff lignites are found in dip-elongate low-sand areas (flood plains) between channel-sand belts. Basinward, laterally continuous lignites coincide with high net sand areas comprised of distributary channel sands indicative of a delta-plain setting. The Wilcox Group is a major aquifer. Maps of resistivity values show that Wilcox channel sands are conduits for ground-water flow. High values of formation resistivity (low total dissolved solids) exist in recharge areas at outcrop and around salt domes. Elongate trends of high resistivity values extend tens of miles basinward and coincide with axes of major sands. Resistivity values decrease basinward and the 20 ohm-m contour delineates the downdip limit of fresh water. Lithofacies and lignite occurrence maps are guides to exploration for deep lignite. Resistivity maps can be used to explore for ground-water resources. End_of_Article - Last_Page 450------------

Exploration Geology and Depositional Modeling of a Continental Tight Sand Reservoir, Abo Formation, Chaves County, New Mexico: ABSTRACT

The Wolfcampian-Leonardian age Abo Formation has been the major objective of exploration efforts in southeastern New Mexico since 1980. The Abo Formation in Chavez County consists of red and green mudstones and shales interbedded with very fine-grained reddish-orange sandstones. The sandstones are subarkosic arenites deposited in a fluvial/delta plain environment on the northwest shelf of the Permian basin. Producing sandstones are characterized by very low in-situ permeabilities (0.006 to 0.01 md) and porosities (determined from CNL density logs) ranging from 5 to 12%. Petrographic analysis of the producing zones yields only traces of visible porosity (^approx 1%), indicating the relative importance of fractures to total porosity. The importance of this secondary porosit is substantiated by the concentration of production within an area of major southwest-northeast-trending buckles that result in folded and fractured zones parallel to their strike. Abo sediments were derived from the predominantly granitic Pedernal uplift to the north and west of the producing area. The prograding fluvial/delta plain is evidenced by calcareous mudstones at the base of the Abo with calcite fracture fillings grading upward into anhydritic mudstones containing anhydrite fracture fillings and bird's-eye lenses. In general, three main producing zones are found in the upper Abo Formation. These sandstones occur either as a single thick (6 to 10 m, 20 to 33 ft) sand or several thin (2 to 4 m, 6.5 to 13 ft) sands separated by thin mudstones. Changes in thickness and character o these three major sands represent lateral shifts in subaerially deposited, braided paleochannels. The relatively homogenous mudstone intervals between producing sands and at the base of the section represent delta switching and tidal backreef (submarine) deposition. Gas wells in the Abo initially produce from 200 to 4,000 MCFGPD of dry (1,000 Btu) gas after considerable acidizing and fracturing. The modeling of the depositional environment of the Abo is critical to the selection of prime drilling locations. Paleochannel development and trends, as well as significant interbedded mudstone intervals, are essential for good Abo potential. Several stratigraphic and diagenetic trapping processes may result in hydrocarbon accumulations within these anastomosed fluvial sandstones. Channel fills are most commonly contained laterally and vertically by mudstones. Differing amounts of calcite and anhydrite cement and argillaceous matrix within the sandstones may create diagenetic traps within the channels. The best Abo wells are located in areas where paleoc annels are well developed and intersect southwest-northeast-trending structural zones. The completion of these wells can be complicated by inadequate cementing prior to fracturing resulting in the fracturing of containing mudstones and shales instead of gas-bearing perforated sandstone intervals. The relatively shallow, 950 to 1,300 m (3,100 to 4,300 ft), depths to encounter pay, combined with the higher allowable tight gas (107) price in the Abo, have stimulated significant activity in this new play that is certain to expand as the reservoir and trapping mechanism is better understood. End_of_Article - Last_Page 476------------

Oil and Gas Developments in Western Canada in 1981

In 1981, there was a marked slump in drilling activity in western Canada resulting from the combined effects of the National Energy Program (NEP), economic recession, and a worldwide oil surplus. The number of wells drilled dropped by 22% to a total of 6,904. Exploratory drilling decreased 19% to 3,074 wells, and development drilling decreased 25% to 3,830 wells. The exploratory success rate also decreased to 62% in 1981, based on 740 oil discoveries and 1,172 gas discoveries. The development success rate decreased slightly to 88%, with 1,334 oil discoveries and 2,034 gas discoveries. Average well depth increased in 4 of the 5 western areas, but total revenue from land sales plummeted to half of the previous years' record totals. Alberta land sale revenue totaled only $58 million, British Columbia $61 million, Saskatchewan $37 million, and Manitoba $2 million. Average price per hectare also dropped, especially in British Columbia where the average price was off by 80%. In relative terms, exploratory activity in Alberta and Saskatchewan dropped to 1978 and 1979 levels, while British Columbia activity was the lowest since 1977. Manitoba was the only province to go against the trend, with a record number of exploratory wells and discoveries. In Alberta, significant exploration activity was centered in the Shekilie, Golden-Evi, and West Pembina areas, while major gas discoveries were made at Whiskey and Elmworth, and oil discoveries at Tangent. No significant new discoveries were made in British Columbia or Saskatchewan, but the 1980 Manitoba oil discovery at Waskada continued to stimulate activity. Preliminary results from the Nechako basin drilling in central British Columbia proved to be disappointing with 3 successive dry holes. In the Arctic Islands, 2 major oil discoveries were made at Skate and Cisco, off Lougheed Island, and a gas discovery at MacLean. Beaufort Sea drilling was hampered by weather, but nonetheless resulted in major oil discoveries at Koakoak and at a Kopanoar follow-up well. The year 1981 will probably be viewed as a major turning point in exploration in western Canada, with interest shifting from the provinces to the frontiers, and the participants mainly Canadian-controlled companies. Cash flow and drilling activity were markedly reduced, mergers and takeovers common, and major heavy oil and tar sands projects cancelled. The expected downturn in exploration during 1981 took place as predicted, and no improvement is seen for 1982.

Nonmarine Depositional Environments and Uranium Exploration in Lower Cretaceous Antlers Formation, North Texas: ABSTRACT

Detailed geologic and geochemical investigations of the Sherman quadrangle for the National Uranium Resource Evaluation (NURE) program have included fluvial deposits of the Antlers Formation which are exceptionally well exposed in cliffs along the shores of Lake Texoma, Grayson County, Texas. These deposits accord with the classical mixed-load, meandering-river model, with erosively based pebbly sandstones grading upward into silty sandstones and carbonaceous mudstones with sporadic lignitic material. Lateral-accretion bedding of presumed point-bar origin is inclined at angles up to 10°. Thickness of these lateral accretion units permits estimates of channel depth of as much as 12 m. Distinct channel forms, some of which are clay filled, are up to 100 m wide, but sub tantially lower estimates of channel width are obtained from dimensions of the point-bar stratification. Flanking and overlying the in-channel sands are inclined levee deposits, chutes and chute bars, proximal to distal crevasse splays, and organic-rich backswamp clays. Preliminary radiometric analyses show low to very low readings for the major channel sands, with a general trend of increasing radioactivity with decreasing grain size, decreasing bed thickness, and increasing organic content. Thus the most distal, or sediment-starved, overbank facies composed of dark laminated clays and lignites show the highest values. These analyses indicate substantial local epigenetic enrichment, but the deposits encountered to date are too small to be considered a potential resource. End_of_Article - Last_Page 831------------

Gas Injection With Radioactive Tracer To Determine Reservoir Continuity-East Coalinga Field, California

Radioactive tracers injected with natural gas revealed that desaturated intervals were often continuous over wide areas of the field; those intervals could greatly influence an injection project by acting as thief zones for injected water. The tracer study suggested generally better reservoir sand continuity than could be inferred from a related outcrop study. Introduction A waterflood pilot project, to start in 1974, has been planned for the Temblor Zone II reservoir of the East planned for the Temblor Zone II reservoir of the East Coalinga field, Calif. This proposed five-spot pattern drive project has required data on reservoir continuity and fluid distribution that have not been readily available from a study of a nearby outcrop nor from modem indirect geological methods., Engineering and geological studies indicated that this gravity drainage reservoir consists of complex channel sand deposits having uncertain interwell continuity complicated by oil desaturated intervals (intervals having a gas saturation and a low gravity-drainage residual oil saturation). Many of these sands contain sufficient movable oil associated with gas intervals to be included in a supplemental oil recovery project. A geological outcrop study was carried out approximately 2 miles northwest of the project study area to develop a conceptual picture of the Temblor Zone II reservoir. To learn more about this reservoir and to follow up the outcrop study, a series of reservoir characterization tests was undertaken. The tests consisted of injecting gas with radioactive tracers into the desaturated intervals. After a study of the out-crop, it was concluded that the subsurface geological features associated with channel boundaries would limit reservoir continuity to the channel width of 300 to 500 ft in all major sands, with better continuity along the trend of the channels. This restricted continuity would severely limit an injection project, but the results of the gas tracer tests indicate that the effective reservoir continuity is much greater than the continuity inferred from the outcrop. Method of Testing Gas tracer surveys were carried out successfully in Temblor Zone II sands, which had desaturated intervals with considerable continuity, Fig. 1 is an oil saturation profile based upon core analysis data for the gas injection well. The oil saturations within the sands having no desaturation have been reduced by the flushing action of the mud filtrate during coring. Some desaturated intervals are shown to overlie movable oil intervals and some desaturated intervals cover entire sand members. The sand in this reservoir is unconsolidated, so in obtaining all rock data, modem procedures for handling unconsolidated core were procedures for handling unconsolidated core were used and rock properties were measured under confining pressure. The well was completed with casing set through the Temblor Zone II formation so that individual sands could be isolated by tubing and packers in the overbore for each of the injection test. packers in the overbore for each of the injection test. The well completion consisted of perforating the desaturated intervals in four sands. To insure that the injected gas had been injected into the right sand, normal radioactive gas injection profile surveys were run at the conclusion of each phase of the testing before the packers were moved. The injection tests were conducted in separate phases using methane containing a radioactive tracer phases using methane containing a radioactive tracer at the constant rate of 500 Mcf/D. JPT P. 1251

A Case History of the Postle Area-Computer Production Control and Reservoir Simulation

The Postle Area Computer Control Operation (PACCO) handles 95 oil wells, 45 water injection wells, and 10 water supply wells about 300 miles from the control computer. After a year's operation, the system showed itself to be highly satisfactory and effective, and pleasing to everyone - whether in operations, engineering, accounting. or management. Introduction Oil reserves were discovered in 1958 in the Pennsylvanian Age sands in the Postle Area of Texas County, Okla., by Republic Natural Gas Co. Step-out wildcats and development drilling established additional production and by 1960 five separate fields were identified. Subsequent development has gradually coalesced these fields to form a major producing area called the Postle Area, located near the center of the Oklahoma Panhandle (Fig. 1). This area now includes 38,000 productive acres and produces approximately 27,000 bbl of oil per day and 35 MMcf of gas per day from 332 producing wells. Five pressure maintenance units are in operation and are currently injecting 70,000 BWPD. Two additional pressure maintenance units are being formed. A computer production control and data acquisition system operates 95 oil wells, 45 water injection wells, 10 water supply wells, five central tank batteries, two production test satellites and four water injection stations in four of the five units. The control computer is located in Oklahoma City, approximately 300 airline miles southeast of the producing properties. Reservoir simulator model studies were used to monitor project performance, design a pressure maintenance program, and change the operational guidelines for a second project. They are expected to result in a 15 percent increase in ultimate oil recovery. The use of computers, of the digital reservoir simulator model, and of the computer production control and data acquisition system has afforded optimum project management of reservoir performance and operations. In 1962, when development was approximately 20 percent complete, Mobil Oil Corp. acquired the Republic Natural Gas Co.'s acreage, which is a significant portion of the oil-productive acreage in the Postle Area. The following is a discussion of the ensuing exploitation of the five major Pennsylvanian Age oil-bearing sands underlying the Postle Area and the computer production control and data acquisition system as it was applied in the Postle Area. Geology The Postle Area is located in the southern portion of the Hugoton Embayment of the Anadarko basin in Texas County, Okla. The Pennsylvanian Age sands in this area underlie a portion of the Permian Age Hugoton gas field. Editor's note: This paper is a combined version of the original manuscripts of "A Review of Postle Area - Development, Unitization, Pressure Maintenance and Computer Applications," by R.A. Irwin, C.W. Tucker, and H.E. Schwartz, Jr.; and "Computer Production Control and Data Acquisition as Applied in Postle Area," by H.E. Schwartz, Jr.

Combustion as a Primary Recovery Process-Midway Sunset Field

Despite the complicated structure of this reservoir, in-situ combustion has been an effective primary recovery process essentially since the beginning of production more than a decade ago. To date, the recovery is 9 million barrels, or 24 percent of the oil originally in placesubstantially higher than the estimated ultimate recovery of 17 percent. Introduction The Moco zone reservoir, located in Sections 34 and 35-T12N-R24W of the Midway Sunset field, Kern County, Calif., was discovered in 1957 and partially developed. However, because there was no demand for the heavy crude, it was essentially shut in until Nov., 1959. It was expected that without fluid injection of some kind there would be a rapid decline in oil production rate. Although there were multiple sands present, the reservoir properties of the Moco zone appeared favorable for in-situ combustion. The structure appeared to be entirely on Mobil Oil Co. property. Predictions of performance under combustion property. Predictions of performance under combustion were based on the results of the South Belridge Thermal Recovery Experiment and on prior supporting work. Evaluation of several methods of operation indicated that the most desirable economics would be obtained if the combustion process were applied immediately. Accordingly, combustion operations were undertaken as soon as practicable after the reservoir was returned to production and development was resumed (this took place in Nov., 1959). Air injection was started in Jan., 1960, at which time the cumulative oil production from the reservoir was 160,000 bbl, or 0.4 percent of the oil in place, and the reservoir pressure was only slightly below its initial value of 1,000 psi. Case histories of other combustion projects have been reported in the literature. projects have been reported in the literature. Reservoir Characteristics The reservoir is a small anticline with six major sands. Structural contours, a type log, and the areal extent of the six sands are shown on Fig, 1. An east-west cross-section (X-X') along the longitudinal axis is shown in Fig. 2. The sands generally are separated by interbedded shales and to the east become thin and disappear. To the west some of the sands merge. The sands were separately identified, correlated, isopached, and designated M1 through M6. This permitted an appropriate design of air distribution permitted an appropriate design of air distribution in the injection wells, which have various combinations of sands open. There are productive zones above and below the Moco reservoir, and the Moco zone itself merges with the Obispo-Pacific fractured shale zone to the east. The presence of these other zones added to isolation problems and costs during development drilling and problems and costs during development drilling and well repair. A north-south cross-section (E-E') across the structure is shown in Fig. 3. The dip is up to 45 degrees to the north and 20 degrees to the south. General reservoir characteristics are as follows: Productive area, acres 150 Average depth, ft 2,100 to 2,700 Gross formation thickness ft 500 Average net sand thickness, ft 129 Porosity, percent 36 Oil saturation, percent 75 Water saturation, percent 25 Formation volume factor 1.06 Initial oil in place, bbl/acre ft 1,980 Initial oil in place, total bbl (millions) 38 JPT P. 981

Comparison of Polymer Flooding and Waterflooding at Huntington Beach, California

Abstract Pilot water flood tests, with and without polymer chemical additives for mobility control, were conducted in the intermediate-viscosity oil reservoirs of the Huntington Beach field, Orange County, Calif. Polymer-treated water was injected into three wells completed in the Lower Garfield sand, and untreated water was injected into two wells completed in the Upper Garfield sand. Both sands are of Pliocene age. The two pilots were observed for approximately 3 years. The polymer flood pilot, having an average oil gravity of 13.2 degrees API, responded within 3 months with both increased oil production and decreased water production rates. The waterflood pilot, with an oil gravity of 18.9 degrees API and mobilities which should be more favorable to water, generally exhibited continued primary oil decline rates and increased water production rates. Results show that the polymer flood was successful and will prove to be economic, while the water flood was uneconomic and has been curtailed. This article compares polymer flooding in one sand with waterflooding in another series of sands in which chances for water alone were significantly better. Introduction The Huntington Beach field is located on the coast approximately 30 miles southeast of Los Angeles (Fig. 1). First commercial oil production was discovered in the Bolsa zone in 1920. During the early 1920's, three wells were completed in the Garfield zone which is stratigraphically equivalent to the Bolsa. However, regular development by Standard Oil Co. of California did not start until 30 years later. Development was slow, extending from 1952 to 1965 and averaged about three well completions per year except for 13 completions in 1962. The Huntington Beach Garfield zone was selected in 1963 to test polymer flooding to determine if a chemical additive for mobility control in intermediate-viscosity reservoirs would economically increase waterflood recovery. Reservoir Characteristics: Geology and Stratigraphy The Upper and Lower Garfield sands in the waterflood and polymer pilots consist of six major Pliocene sands located between 1,600 and 2,500 ft. The five Upper Garfield sands can be subdivided into at least 15 minor correlative members. The Lower Garfield sand contains correlative horizontal members; however, several injectivity profiles suggest that this sand performs as a single homogeneous sand body (Fig. 2). The structure in the two pilot areas at the Upper Garfield level is a northwest-southeast trending anticlinal nose with a major axial fault (Fault A, Fig. 3) and minor transverse faults. The throw of the major fault increases with depth; however, horizontal displacement greatly exceeds vertical displacement. Fig. 3 illustrates the structure at the fourth Upper Garfield sand level. The major Upper Garfield sands are blanket-type on both sides of the fault and are correlative throughout the area. Most minor members of the major sands are continuous, but some sand discontinuity is present. The major uplifting and faulting occurred after deposition was completed.

Ground Water Sanitation at Houston, Texas

Houston, Texas, with a population of 292,352, according to the 1930 Census, is the largest City in the United States depending entirely upon ground water for its municipal water supply. This fact has afforded excellent opportunity for the study of the quality of ground water and the factors that influence the sanitary quality of this type of supply. The purpose of this article is to show from actual data, accumulated over a period of years, just what can be expected from wells in this area, particularly from the viewpoint of sanitation. The data presented are the result of an intensive study of the sanitary quality of ground water, initiated and carried out by the Engineering Division of the Water Department of the City of Houston as part of its operating program. The underground water at Houston is drawn from unconsolidated sands probably of the Pleistocene and Pliocene series. The water bearing formations are known locally as Lissie and Reynosa and consist essentially of sands, clays and shales laid down in more or less thin beds. Although these beds vary a great deal in thickness from place to place the major sands are probably continuous throughout the area. The dip is in a southeasterly direction about 35 feet to the mile and the strike is about north 45 degrees east. The alternate beds of sand and impervious clay due to their inclined positions give rise to many artesian conditions. A strip along the Gulf extending inland about 15 miles north of Houston is covered with a formation of predominantly clay (Beaumont Clay) that also serves as a splendid restraining formation to prevent the upward escape of water from the water bearing sands of the deeper Lissie and Reynosa formations. Mechanical analyses of these sands show that about 25 percent of the sand grains are between 0.50 and 0.25 millimeters in diameter; about 50 percent between 0.25 and 0.125 millimeters and about 15 percent between 0.125 and 0.062 millimeters in diameter. The other