Main Sand Bodies Research Articles

Sedimentary characteristics and implications for hydrocarbon exploration in a retrograding shallow-water delta: An example from the fourth member of the Cretaceous Quantou Formation in the Sanzhao depression, Songliao Basin, NE China

Based on the analysis of core, logging, and testing data, the fourth member of the Cretaceous Quantou Formation (K2q4) in the Sanzhao depression, Songliao Basin, is investigated in order to understand the sedimentary characteristics and hydrocarbon exploration significance of a retrograding shallow-water delta. The results show that during the sedimentary period of K2q4, the Sanzhao depression with a gentle basement experienced stable tectonic subsidence and suffered a long-term lake level rise caused by paleoclimate changes (from semiarid to semihumid), the K2q4 in the study area were dominated by a fining-upward deltaic succession and had relatively stable thickness. From the bottom to the top, the color of mudstone gradually changes from purplish-red to gray and grayish-green, the contents of caliche nodules decrease gradually, while the presence of pyrite in sediments becomes frequent. Channel sandstones mainly composed of siltstone and fine sandstone with developed high-energy sedimentary structures constitute the main sand bodies of deltaic deposits, but the scale of channel sandstones decrease upward. Despite the long-term lake level rise and fining-upward sedimentary succession, purplish-red mudstone, caliche nodules and thin channel sandstones are still broadly distributed in the study area, and thin channel sandstones can be found at the top of K2q4 covered by the black oil shale of Qingshankou Formation. These assertations suggest that the study area was dominated by retrograding shallow-water delta deposits during the sedimentary period of K2q4. In comparison with modern Poyang Lake, we infer that during the sedimentary period of K2q4, the study area experienced frequent lake level fluctuations triggered by paleoclimate changes despite the long-term lake level rise, and the lake level fluctuations control the deposition of retrograding shallow-water delta. In addition, most of the thin channel sandstones distributed at the top of K2q4 and covered by black oil shale are generally immersed in oil, indicating that the thin channel sandstones formed at the top of a retrograding shallow-water delta sedimentary succession are favorable targets for lithological reservoir exploration.

Sedimentary characteristics and sand-body distributions in the Lower Permian He 8 Member, Ordos Basin, China

The Lower Permian He 8 Member (P1h8) in the Ordos Basin is a typical producing zone of tight lithologic gas reservoirs. Analyses of sedimentary characteristics, electrofacies, and sand-body distributions of P1h8, conducted on modern fluvial deposits, outcrops, cores, and well logs, revealed that braided rivers that developed in the Lower P1h8 and Upper P1h8 are characterized by meandering river. Within these fluvial deposits, the procedure consists of analyzing high-resolution sequence stratigraphy and sedimentary dynamics defined from calibrated logging curve signatures and depositional studies. According to modern and ancient fluvial deposits, we have developed a process-based sedimentary conceptual model for interpreting and predicting the distribution and geometries of sand bodies in braided and meandering deposits. The main sand body of the braided river system was bars and channel fill deposits. The braided river sand bodies are distributed over multiple vertical superimpositions and overlapping horizontal connections. The meandering river sand bodies are mainly point-bar deposits, which are bead-shaped and exhibit scattered development in the vertical direction. This comparison indicates that there were significant differences between braided and meandering deposystems. The sand bodies in the Lower P1h8 were multidirectionally connected and primarily distributed in a stacked pattern. In contrast, the sand bodies in the Upper P1h8 were distributed in an isolated manner, and fine grains (mud and silt) were deposited between the sand bodies with poor connectivity. We interpreted the fluvial deposits that control the distributions of the sand body of the He8 Member in the eastern Sulige gas field and constructed a corresponding prediction model of a braided-meandering reservoir. This model will promote understanding of the extent of fluvial deposits and sand-body distribution of P1h8, thus elucidating hydrocarbon-bearing sand units of the Ordos Basin for future exploration.

Study on reservoir description technology of complex fault block oilfield——Taking the South 1st member of D sag as an example

The D sag has developed faults, serious erosion and fault loss, developed glutamate, strong heterogeneity, and large formation dip, which makes stratigraphic comparison difficult and unclear understanding of oil reservoir and oil-water relationship during the development process. For this reason, this study was carried out. On the basis of the existing seismic interpretation results, carry out the fine structural interpretation of the main sub-layers in the study area; carry out the study of sedimentary characteristics, divide the sedimentary facies, and clarify the sedimentary characteristics of the main sand bodies; use the core analysis data to establish the interpretation of physical parameters in the study area model, and establish a fine three-dimensional geological model, through the study of oil-water distribution law, carry out potential research, and select favorable well-distributed blocks.

Applying seismic attributes on finding the petroleum potential of stratigraphic traps in upper oligocene “C”, blocks 09-1,09-2/09, center of Cuu Long Basin

The article focuses on applying conventional seismic structural interpretation and seismic attributes in conjunction with supportive surrounding well logs to qualitatively find out any indication of sand stratigraphically trapped in Oligocene “C” sediment, the center part of Cuu Long basin where the studied area, a mono-cline structure, has been considered as one of the main depo-center which has a dominant potential of source rocks rather than reservoirs. The conventional attributes show an elongate abnormal zone developing North-South in the studied area. Detailed interpretation and surface attributes application at reservoir scale showing a clearer image of the sand and shale distribution qualitatively, two main sand bodies have been captured from the impedance surface attributes and shale distributions are also roughly generated. Within this paper, the authors only expect to predict the distribution of the sand bodies in Oligocene “C” sediment that could open new opportunities of attracting more exploration effort on stratigraphic traps then discoveries in exist in the slope of Oligocene “C” sequences at the blocks 09-1,09-2/09 center part of Cuu Long basin. Despite recent years, more hydrocarbon accumulations have increasingly been discovered in the target, but to reveal the full potential of stratigraphic traps, further studies need to be carried out to quantitatively evaluate the oil and gas potential of these stratigraphic/ combination traps. However, many uncertainties related to the petroleum system need to be analyzed to minimize the risk before turned into other further costly exploration activities. And at least the study could narrow down the studied area and attract more attention to exploration efforts in the future. Further quantitative interpretation efforts on the hydrocarbon detection, sealing capacity of these traps need to be invested in order to increase the success probability of the targets for the proper exploration and/or appraisal plan of stratigraphic traps in the future.

Study on the Variogram Analysis Methods of 3D Geological Modeling for Sandstone Reservoirs

Variogram analysis is a necessary step for 3D stochastic modeling. Different variogram settings will directly affect the final distribution characteristics of model attributes. Setting the variogram parameters on the optimization results of sedimentary types of sub-units has become a key step in geological modeling. In this paper, the influence of variogram parameters on the simulation results of reservoir properties is studied to improve the analysis method of the variogram. This paper is for typical river-delta sedimentary reservoirs, specifically taking the SII7+8 layers as the research object. Multiple sedimentary microfacies types, including river, abandoned river, floodplain, natural dyke, coexist and show highly heterogeneous in the SII7+8 layers. On this basis, the reservoir is divided into 3 types of sand bodies and 11 kinds of sedimentary microfacies according to the effective thickness, sedimentary conditions, scale and shape of main sand bodies to study the distribution characteristics and extension scale of different sedimentary types in plane, so as to determine the variogram parameters of different sand body types, and accurately simulate the reservoir property distributions. The process in variogram analysis methods can further improving the accuracy of 3D geological modeling.

Source to sink transport in the Oligocene Huagang Formation of the Xihu Depression, East China Sea Shelf Basin

Abstract The Huagang Formation is the most important hydrocarbon reservoir in the Xihu Depression of the East China Sea Shelf Basin. Reconstructing the provenance and transport pathways of its main sand bodies is of great significance to oil and gas exploration. Previous provenance studies were mainly based on heavy mineral analyses and showed multiple source areas, but so far quantitative estimates on provenance are lacking. Detrital zircon U–Pb dating combined with heavy mineral analysis is an effective tool to quantitatively investigate sediment provenance. In this paper, we use the LA-ICP-MS method for U-Pb dating of detrital zircons of 18 samples from 13 drill cores in the Xihu Depression to determine the sediment provenance of the Oligocene Huagang sandstones. The U-Pb zircon dating results show three different age groups, in which Precambrian ages dominate (∼60%), and Paleozoic and Mesozoic ages each account for ∼20%. The Precambrian zircons are mainly derived from the Hupijiao uplift, which indicates a dominant and long-distance north to south transport direction. The provenance of the Paleozoic zircons is mainly from the Diaoyu Islands Folded-Uplift Belt in the east, while the Haijiao and Yushan uplifts in the west are the main source region for the Mesozoic zircons. The northern provenance transport pathway is dominated by axial channels. Incised valleys are observed in the western source and a transfer zone dominates the eastern provenance. The integration of all data results in a new schematic model of source to sink transport in the Huagang sandstones, demonstrating the complexity of multiple source rocks and sediment transport pathways in the Oligocene Xihu Depression.

Genetic types and sedimentary model of sandbodies in a shallow-water delta: A case study of the first Member of Cretaceous Yaojia Formation in Qian'an area, south of Songliao Basin, NE China

Abstract Based on outcrop, core, logging and mud logging data, and modern deposition analog, the sandbodies genetic types and spatial distribution in different facies belts of the shallow water delta in the first Member of Cretaceous Yaojia Formation (K2y1) of Qian'an area in Changling sag of southern Songliao Basin were analyzed, and the sedimentary model of shallow water delta was established according to deposition process. Active channel sandbodies, point bar sandbodies and bifurcation bar sandbodies in distributary channels and complex sandbodies formed the main sandbodies in the delta plain, while terminal distributary channels and mouth bar sandbodies formed the main sandbodies in the delta front. The delta prograded gradually under the construction of river mouth and reconstruction of river erosion, the early delta front evolved into delta plain and was reformed by distributary channels, and new delta fronts were formed at the river mouth ahead constantly. Under the control of the above deposition process, the size of main distributary channels in delta plain-delta front declined, while mouth bars developed increasingly. The sandbodies of different genetic types formed framework of river-dominated shallow water delta. The point bar and active channel sandbodies in main distributary channels of the delta, with the best reservoir quality, are lithologic reservoir targets in future exploration.

New Technologies Maximize Production in Viscous-Oil North Slope Field

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 171896, “The Use of New Technologies To Maximize Oil Production in a Viscous-Oil Field in Arctic Environment: The Nikaitchuq Experience,” by S. Raniolo, SPE, S. Mancini, and S. Vimercati, Eni E&P; and P. Gentil, D. Simeone, SPE, and A. Buchanan, Eni Petroleum, prepared for the 2014 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 10–13 November. The paper has not been peer reviewed. Oil quality and drilling-pad constraints for a viscous-oil field defined a development scheme that consisted of a waterflood line drive with horizontal producers and water-injection (WINJ) wells side by side. Different well designs for producer wells were implemented: a single horizontal trajectory undulating between the two sand bodies in counterphase with the related water injectors, a fishbone design with the main borehole in the lower sand and multiple branches in the upper sand, and a multilateral (ML) counterphase design with extended-reach undulating dual laterals. As a result of the ML campaign, well productivity doubled. Introduction The field is located on the North Slope of Alaska in the Beaufort Sea in water depth less than 20 ft. The reservoir consists of four zones hydraulically communicating, named OA1, OA2, OA3, and OA4. The differentiation is mainly sedimentological; OA1 and OA3 are associated with a more-proximal depositional system, while OA2 and OA4 are characterized by a predominance of thin laminated silty sandstones because of a more-distal depositional system. The crude quality and drill-pad constraints (one offshore, one onshore) drove a development concept that consisted of a waterflood line drive with alternating horizontal producers and WINJ wells with a 1,200-ft spacing. The lateral sections are 6,000–10,000 ft long through the reservoir with undulating counterphase trajectories across the two main sand bodies. Challenging very-extended- reach wells with a stepout ratio higher than 6 have been achieved (Fig. 1). The undulating counterphase well trajectories were selected for producers and injectors to guarantee optimal pressure support and avoid early water breakthrough. The original design was based on predrilling assumptions; however, the reservoir was revealed to be more homogeneous than expected, with good petrophysical properties. These conditions led to the evaluation of ML concepts, with an expected low impact on water-cut trends and water breakthrough. With the goal of increasing reservoir contact, the ML concept consisting of undulating counterphase dual laterals was tested in August 2013. The producer was modified to an undulating counterphase dual lateral throughout the two main sands. The injector maintained the original well concept in counterphase with the original producer mainbore. As a result, well production doubled with respect to the average before the intervention. In parallel, key development wells were identified for data acquisition and appraisal activities that have resulted in derisking stepout opportunities as well as assessing the potential of challenging resources, such as the peripheral areas.

Sedimentary and evolutionary characteristics of dereliction deltas in Chang 6 – Chang 2 oily members, Zhidan region, northern Shaanxi

Abstract The study using well logging data and the sedimentological method reveals that large deltas and lake systems developed time and again in the Chang 6 –Chang 2 depositional stage in the Zhidan region, and a good intraplot source-reservoir-cap assemblage and widespread oil-bearing series are formed. In sub-south-north cross-section, the Chang 6–Chang 2 sedimentary association shows that deltaic deposits progressively overlap lake deposits from the bottom to the top and from the north to the south, forming upward coarsening dereliction depositional sequences; sedimentary facies belts moved continually toward the lake center from north to south, deltafront subfacies spread extensively and overlapped in multiphases, forming the main intraplot depositional body. Deltafront subfacies could be subdivided into underwater distributaries plain and anterior margin river mouth subfacies, and the main sand bodies are river mouth sand bank and distributaries channel sand body. The Chang 6 stage's anterior margin river mouth subfacies in the region were well-developed. The Chang 2 stage's underwater distributaries plain subfacies extended and developed rapidly, and deltaic plain subfacies began to come into the region.

Estratigrafia de Seqüências Aplicada à Caracterização de Aqüíferos: um Estudo de Caso na Área de Candiota, Rio Grande Do Sul

Detailed stratigraphic analysis of the Early Permian (Artinskian/Kungurian) succession of the intracratonic Paraná Basin in southernmost Brazil has been applied focusing stratigraphic characterization of potential aquifers. In the study area, the counties of Candiota and Hulha Negra, in the southwestern region of Rio Grande do Sul state, the sedimentary succession (Itararé, Rio Bonito and Palermo units) is interpreted to have been formed in a shallow, wave-dominated sea, originated mainly in a mixed (tide and wave) influenced estuary setting. Four main depositional systems have been recognized: alluvial fan, fluvial-dominated delta, lagoonal estuary and barrier/shoreface. The regional correlation of the lithofacies within the different depositional systems has led to a high-resolution stratigraphic framework, with three third-order depositional sequences (i.e., unconformity-bounded depositional packages formed during a complete cycle of falling and rising base level). The main sandbodies occur within sequence 2 which is formed by seven fouthorder parasequences, and at the base of the third sequence. Under the viewpoint of groundwater prospecting, the best sandbodies occur within parasequences 1,2 4 and 7. Based upon the stratigraphic characterization, optimal borehole locations are given, as well as estimatives on productive dephs and water volume.

Patterns of Sedimentation in the Oficina Formation Central-West Part of Greater Oficina Area, and Their Relationship to Occurrence of Oil and Gas

The Chimire-Boca-Nipa fields are located in the western part of the greater Oficina area an the study covers approximately 800 km[sup 2]. A geological model for the Oficina Formation (lower-middle Miocene) based on electric log analysis, petrophysical evaluation, core, electrofacies and isopach maps, seismic data analysis, has been made. The Oficina formation is formed by successive transgressive and regressive cycles, being the most important the ones located in the lower-middle section of this formation. In this area a fluvial-deltaic system has been identified, where a great number of transgressive-regressive parasequences prevailed. This system consists of three (3) main sub-environments; alluvial valley, delta plain and delta front. The main sand bodies are formed in distributary channels, meander bars and deltaic couples. Occasionally crevasse splays, with associated sandy rupture facies, caused by flooding of the interdistributary bay are recognized. In general, these main sand bodies have a northerly orientation. The structure of the area is dominated by a gentle (2-3[degrees]) northerly dip. Oil and gas reservoirs are associated with east-west trending normal faults which cuts this homocline. There is also an element of stratigraphic trapping, as the reservoirs change laterally to shale or low porosity sandstone. This study has highlighted 20 new more » prospects which increased the STOIP probable and/or possible by 350 mmb of light oil. Additionally the new geological interpretation of these mature fields will allow improved recovery projects in this area. « less

The Ivanhoe/Rob Roy Fields: Operational Innovation on a Major Subsea Development

Summary The Ivanhoe/Rob Roy development consists of a floating production facility(FPF) serving two remote subsea production/injection production/injectionmanifolds and well clusters. These clusters, about 2 miles apart, consist ofnine production and six injection wells depleting five separate hydrocarbonaccumulations. The field development philosophy has centered on usingstate-of-the-art hardware and techniques to achieve optimum exploitation ofreserves. A strong emphasis on safety is reflected in all aspects of theproject from design to operation. This paper describes the development after 1year in operation. The approach taken will be of interest to other North Seaoperators contemplating marginal subsea tiebacks or stand-alonedevelopments. Introduction The lvanhoe and Rob Roy fields are located in the U.K. Sector, Block 15/21a, about 110 miles northeast of Aberdeen. Monsanto Oil Co. was awarded the blockas operator during the fourth U.K. licensing round in March 1972. Ivanhoe wasdiscovered in 1975 with Well 15/2 1a-3 and was considered uncommercial untildiscovery of the Rob Roy accumulation 9 years later. Discovery Well 15/21a-11located roughly 2 miles east of Ivanhoe provided sufficient reserves forcommercial development of both fields through a single facility. Developmentplans for the field were already under way when, in late 1985, Amerada Hess Ltd. acquired Monsanto's U.K. interests and, consequently, operatorship of Block 15/21a. Annex B approval for the single development of both fields wasgiven in early 1986. The dramatic fall in the price of oil during 1986 led to areappraisal of the project economics, which delayed construction. Conversion ofthe semisubmersible Sedco Philips SS began in April 1987, and Philips SS beganin April 1987, and development drilling began in July 1987. First oil from thefields was achieved on July 7, 1989, ahead of schedule and within the 1986revised budget. As development of the Ivanhoe and Rob Roy fields progressed, exploration in the Block 15/21 area continued, resulting in the discovery ofthe Hamish field with Well l5/21b-21. This field was appraised, developed, andput on production 2 years after its discovery using the existing Ivanhoe/Rob Roy infrastructure. Figs. I and 2 show the location of Block 15/21 and the Ivanhoe/Rob Roy facilities. Reservoirs The Ivanhoe and Rob Roy reservoirs, located in the Upper Jurassic Pipersandstone, were formed as a result of an upthrown fault closure. Figs. 3 and 4show a plan and cross-sectional view of the reservoirs, respectively. Eachreservoir contains two main sand bodies separated by a continuous shale member. Classed as the Main and Supra Piper sands, they are highly porous and have Piper sands, they are highlyporous and have very high permeabilities and very low connate watersaturations. The Main Piper sands are thicker and generally of better qualitythan the Supra Piper sands. The reservoirs are located at roughly 8,000-ft truevertical depth subsea (TVDSS) and are normally pressured. Virgin reservoirpressure in both reservoirs was found to be the same (3,510 psia at 7,700-ftTVDSS), and the reservoir temperature of 175 degrees F was normal for the depthof burial. The field has three distinct crude types. The Ivanhoe crude in both Piper sands is the same, but the crudes in the Rob Roy Main and Supra Pipersands differ. During appraisal testing, the reservoirs were found to have asmall but significant CO2 content (=1% in gas) and a trace of H2S. Table Isummarizes the reservoir and crude properties. properties. The formation waterin both the Ivanhoe and Rob Roy fields is essentially the same and much moresaline than North Sea seawater. Total dissolved solids are around 100,000 mg/Lwith a chloride content of about 60,000 mg/L. Barium and bicarbonate are high(150 and 300 mg/L, respectively), indicating a potential for barium sulfate andcarbonate scaling in injection and production wells. production wells. A simplelinedrive water-displacement pressure-maintenance system was adoptedpressure-maintenance system was adopted as part of the reservoir developmentscheme. The Main and Supra Piper sands in both reservoirs were considered to bepressure isolated by the intervening middle shale member. Therefore, thestrategy to deplete the Main and Supra Piper sands in both fields independentlywas incorporated into the completion design described later. Total stock-tankoil initially in place for the fields has been estimated at 199 MMSTB, with areserve of 106 MMSTB estimated over the 10-year field life. After 12 months ofproduction, about 20% of total reserves has been produced. As predicted, nowater breakthrough has occurred to date and no major reservoir managementproblems have been encountered. Carter and problems have been encountered. Carter and Morel1 described the reservoir performance during the first year ofproduction. performance during the first year of production.

High-Energy Carbonate-Sand Accumulation, the Quicksands, Southwest Florida Keys

ABSTRACT High-resolution seismic-reflection profiles of the Quicksands, located along a broad ridge on the platform shelf west of Key West, Florida, indicate a significant deposit of non-oolitic carbonate sand occurs in a belt 47 km long by 28 km wide. The surface of the belt is ornamented by large (5 m), migrating tidal bars, oriented in a north-south direction, on which sand waves, oriented in an east-west direction, are superimposed. Some of the sand waves are awash at low tide. The sand waves are formed by strong reversing tidal currents flowing between the Gulf of Mexico and the Straits of Florida. The waves migrate directly over Pleistocene bedrock to the east, but the deposit thickens to the west and sand waves there overlie non-oolitic Holocene accumulations as thick as 12 m. Westward- ipping accretionary bedding indicates that net migration of the sands is to the west, despite north-south movement of tidal currents. The westward edge of the accumulation has accreted over deeper, muddier deposits. Although tidal currents and resultant bedforms appear identical to those of active ooid deposits in the Bahamas and elsewhere, no oolitically coated grains were found in this study. Thin-section analyses show the principal component (average 48%) of the sands is fragmented plates of species of the green alga Halimeda, followed by particulate coral (average 17%), which increases off the flanks of the main sand body. Short vibracores confirm the presence of cross-bedding.

Regional Inventory of Peace River Oil Sands, Alberta, Canada: ABSTRACT

The Peace River oil sands of northwestern Alberta contain an estimated 92 billion bbl of bitumen trapped in an updip pinch-out of the Lower Cretaceous Bluesky and Gething Formations. The geologic reservoir characteristics of the Peace River oil sands are being mapped on a regional scale through the use of core and geophysical logs. Four wells per township are used wherever possible. A computerized data file on each well consists of basic well data, tops of the Bluesky and Gething Formations, and oil sand reservoir and the underlying pre-Cretaceous unconformity, and a coded lithology log. The lithology log is kept simple due to the limits of geophysical log interpretation but attempts to quantify sand, shale, interbedded sand and shale, oil, and water. Logs have been calib ated wherever possible with core control. Because the data are stored as a log of the well, a wide variety of useful maps can be generated by the computer. These include maps showing structure, sand/shale ratios, gross and net pay thicknesses, basal water, top water, lean zones, and uninterrupted pay. Recognition of four major facies including continental, tidal flat, shoreline and shallow marine, and tidal channel deposits has led to the proposal of an estuarine model for sedimentation within the Gething Formation. Isopach maps from the top of the Bluesky and Gething Formations down to the pre-Cretaceous unconformity show a regional southeast to northwest drainage trend on the unconformity surface. Similar trends are seen in the main sand bodies. Coordination of computer-generated maps with the facies model highlights areas which satisfy specific criteria that may be critical in determining the applicability of a particular in-situ recovery method. End_of_Article - Last_Page 543------------

Facies Control on Bitumen Saturation, Peace River Oil Sands Deposit, Alberta, Canada: ABSTRACT

In the Peace River oil sands deposit an estimated 75 billion bbl of heavy oil are trapped at the updip pinch-out of the Lower Cretaceous Bluesky and Gething Formations, at depths of 1,500 to 2,500 ft (457 to 762 m). The principal oil-saturated sand body occurs near the updip edge of the reservoir and averages 80 to 100 ft (24 to 31 m) in thickness. Downdip, the Gething Formation thickens to over 250 ft (76 m) but becomes mainly shale with a few thin sands. Throughout the area it is capped by thin marine sands of the Bluesky Formation. Based upon palynology and sedimentary structures, this sequence grades upward from continental through brackish to marine. Sedimentary structures of a channel sequence are clearly displayed in the main sand body. From bottom to top the sequence is: a channel lag deposit containing abundant disoriented detrital carbonaceous fragments, plane-bedded or structureless sand, large scale cross-bedded sand, smaller scale cross-bedded sand, and structureless or bioturbated sand containing abundant glauconite. Laterally this sequence commonly grades into thinly interbedded oil-saturated sand and shale. Reservoir properties vary between the facies. The channel lag deposits have coarser grain size, less interstitial End_Page 776------------------------------ clay, and generally lower oil saturations than the thinly interbedded sand and shale. The cross-bedded sands contain the highest oil saturations and form the largest and most continuous reservoir. Oil saturations are commonly lower in the marine sands of the Bluesky Formation where glauconite, clastic carbonate, and local carbonate cement combine to reduce porosity and permeability. End_of_Article - Last_Page 777------------

Successful Stimulation in the Cotton Valley Sandstone - A Low-Permeability Reservoir

Thorough evaluation of field results in the Cotton Valley sand resulted in a dependable, successful approach to stimulation. This paper presents a history of the development of this approach and verifies successes with case histories of Cotton Valley wells. Introduction The Cotton Valley sandstone, located in north-central Louisiana and East Texas, is an extensive, coastal strand-plain sandstone deposition. Formation permeability and porosity are very low and stimulation is necessary permeability and porosity are very low and stimulation is necessary in most Cotton Valley wells to obtain economic production. Because of the depth of the formation (8,000 to production. Because of the depth of the formation (8,000 to 12,000 ft) and the reservoir temperature encountered (230 to 280 deg. F), the choice of fracturing procedures is somewhat limited. During the past 3 years, much success has been obtained with hydraulic fracturing using moderately viscous, temperature-stable, aqueous gel systems. Recently, in wells where fracturing-fluid retention has been a problem, the use of low-surface-tension surfactants and problem, the use of low-surface-tension surfactants and carbon dioxide with the fracturing fluid has helped improve fracturing-fluid recovery after treatment and has provided encouraging stimulation results. provided encouraging stimulation results.After a thorough evaluation of field results in the Cotton Valley sand, a dependable, successful treatment has been developed. This paper provides a history of the development of this approach and verifies present successes with case histories of Cotton Valley wells. Geologic Description Since drilling activity began on a large scale in north-central Louisiana in the early 1950's, the presence of an extensive group of sand bodies called the Cotton Valley Group has been known. The geological deposition of the area became better defined as well-control information was obtained. As early as 1944, Swain was able to describe geologically the over-all deposition history of the group of Upper Jurassic sands known as Cotton Valley. Swain also described Upper Jurassic deposition in northeastern Texas. In 1954, Forgotson further described these sediments and added some changes to Swain's descriptions. More recently, Thomas and Mann further defined the depositional trend of the Cotton Valley. This description is still believed to be fairly accurate. A general map of the Cotton Valley deposits and areas of interest is shown in Fig. 1. The sand member is 500 to 600 ft thick and grades into a thinner marine deposition, dipping to the southwest. The main sand body pinches out to the north with an east-west line in southern Arkansas and becomes lenticular in eastern Louisiana. During Late Jurassic time, the coast that bordered the Gulf of Mexico extended east and west across southern Arkansas. Parallel with the coast line, a long-shore barrier island in northern Louisiana separated a coastal lagoon in northernmost Louisiana from the open Gulf on the south. A delta that was formed by the ancestral Mississippi River in northeastern Louisiana and adjacent Mississippi supplied sand to the long-shore barrier island. The Late Jurassic coastal features are reflected clearly in the composition of the rock of the Cotton Valley Group. A well log showing "typical" Cotton Valley deposition is shown in Fig. 2. JPT P. 1267

Braided Rivers and Related Terrigenous Depositional Systems--Useful But Enigmatic Exploration Models: ABSTRACT

Closely related Holocene and Pleistocene braided-fluvial, eolian dune-sand flat, and playa-lake depositional systems in the eastern Texas Panhandle represent a useful but complex model for hydrocarbon exploration in ancient continental sediments. The modern South Canadian fluvial system and the Pleistocene Borger fluvial system are braided river deposits which are distinguishable from other sand bodies by multi-lateral sand-body geometry (high width/thickness ratio), low channel sinuosity, few sedimentary structure types, poor lateral and downstream continuity of individual depositional sequences, punctuations of these sequences by thin clay drapes, and a high sand/mud ratio. The main sand body of the South Canadian system averages two mi in width and 125 ft in thickness nd cuts into the coarse-grained and sometimes conglomeratic sand of the Borger system. Fine to medium wind-polished sand of the Lake Marvin eolian-dune system and the older vegetated Nix Ranch eolian-sand system is deposited in thin plane-bedded sheets and strongly cross-stratified parabolic and longitudinal dunes. These eolian units are derived from, and often continuous with, South Canadian fluvial deposits of different ages. The strongly vegetated and older Pampa eolian-sand system is related similarly to the Borger fluvial system. In addition, the surface of the Pampa system is pockmarked by small pre-Nix Ranch playa-lake deposits consisting of organically rich and finely laminated beds of clay and sandy silt. Hydrocarbon discoveries in fluvial and eolian sands illustrate the economic value of this depositional model. Among the many examples of production from fluvial sands are the Lower Cretaceous J sand bodies in Nebraska, lower Paleozoic Granite Wash in Alberta, and the Berea sand in Ohio. The Permian Queen sandstone in New Mexico produces from probable eolian deposits. Limited subsurface information leads to difficulty in recognizing separate depositional systems in sands of similar size and texture. For this reason the explorationist must be careful in application of depositional models. Realization of possible variation in sand-body geometry in a particular type of depositional system is essential. End_of_Article - Last_Page 914------------

Bellshill Lake--Thompson Lake Cretaceous Oil Fields, Alberta: ABSTRACT

The Bellshill Lake oil field, located in east-central Alberta, was discovered in 1956. The field represents a stratigraphic trap formed by updip (northeast) shale-out of a highly porous and permeable quartz sand within the Lower Cretaceous Mannville formation. A detailed lithofacies map of a 50-foot thick slice (including the productive unit) parallel with an overlying marker bed shows: (1) the updip limit of the productive sand is irregular, and (2) ridges of sand are built up on the upper surface of the main sand body and are responsible in part for maximum pay thicknesses. The field is overlain by a gas cap and underlain by water. The maximum oil pay thickness is 50 feet. Approximately 3,000 acres have been developed to date and primary recoverable reserves are estimat d at 40 million barrels of 27° gravity (API) oil. The Thompson Lake field discovered in 1958 is a similar but smaller field and lies on trend southeast. A new technique for determination of net permeable sand (in sand-shale sequences) from electric logs is presented. The technique involves: (1) analysis of drill-stem test and lithologic data, and (2) construction of a graph to correct the amplitude of the self potential (SP) curve for various mud resistivities. End_of_Article - Last_Page 1095------------

Horseshoe-Gallup Field--Preliminary Report: ABSTRACT

The Horseshoe Canyon-Gallup field, T. 30-31 N., R. 16-17 W., San Juan County, New Mexico, was discovered in September, 1956. It now contains approximately 90 wells. The field produces from the Gallup formation of the Mesaverde group. The oil accumulations are stratigraphic and occur in highly localized sandstone lenses. The thickness of these lenses ranges from a feather-edge to more than 20 feet. Although numerous lenses are present, they are usually referred to as belonging to one of the two sands. The upper sand, which consists of several interbedded sandstones and shales, is the most widespread. It produces throughout the field. The lower is long and narrow. It generally consists of not more than two main sand bodies with thin lenses, in places found above and below. It is found throughout the northwest-southeast extent of the field. Structural information to date is adequate to indicate that it bears only a minor relation to accumulation. Shallow depths and substantial reserves make this field possibly the best oil investment in the Four Corners area. Average depth is 1,400 feet with over-all cost of approximately $20 per foot for a completed well. Producible oil reserves per well vary due to the lenticular nature of the reservoirs; however, 3,000 barrels per acre is average. Pay-out period is approximately 7 months with a 4:1 ratio of investment to return. Future exploration for this stratigraphic type of Gallup accumulation should be limited to the End_Page 1100------------------------------ band of deposition between the area of continuous beach sands and the seaward pinch-out of the Gallup tongue. In addition, fractured reservoirs with poorly developed sands could be expected throughout this band and for a short distance seaward. End_of_Article - Last_Page 1101------------

Adena Field, Morgan County, Colorado: ABSTRACT

With the discovery of stratigraphically trapped oil in Washington County, Colorado, in 1952, interest in the south-central part of the Denver basin greatly increased, resulting in the discovery of the Adena field in 1953, the largest reserve developed to date. The Dakota J reservoir embraces approximately 12,000 acres and contains substantially more than 40 million barrels and 32 billion cubic feet of recoverable oil and gas. During the first year of production, more than 3 million barrels of oil were produced, resulting in a pressure decline of 92 pounds. Oil is produced predominantly from the Dakota J sandstone and secondarily from the Muddy D sandstone of Cretaceous age. Structurally the field is characterized by relatively uniform northwest dip of approximately 50 feet per mile, though local terracing and nosing exist. Accumulation is controlled by stratigraphic variation within and below the producing zones. Locally, a permeability barrier is present on the eastern side of the field, while a basal seal below the pay zone prevents migration into the main sand body. Most of the oil now produced in the Muddy D sandstone is found in the northwestern extremity of the field and is associated with those areas where the formation has its best development of porosity, permeability, and thickness. End_of_Article - Last_Page 531------------