Conglomerate Reservoir Research Articles

Quantitative evaluation methods for water-flooded layers of conglomerate reservoir based on well logging data

The rapid changing near source, multi-stream depositional environment of conglomerate reservoirs leads to severe heterogeneity, complex lithology and physical properties, and large changes of oil layer resistivity. Quantitative evaluation of water-flooded layers has become an important but difficult focus for secondary development of oilfields. In this paper, based on the analysis of current problems in quantitative evaluation of water-flooded layers, the Kexia Group conglomerate reservoir of the Sixth District in the Karamay Oilfield was studied. Eight types of conglomerate reservoir lithology were identified effectively by a data mining method combined with the data from sealed coring wells, and then a multi-parameter model for quantitative evaluation of the water-flooded layers of the main oil-bearing lithology was developed. Water production rate, oil saturation and oil productivity index were selected as the characteristic parameters for quantitative evaluation of water-flooded layers of conglomerate reservoirs. Finally, quantitative evaluation criteria and identification rules for water-flooded layers of main oil-bearing lithology formed by integration of the three characteristic parameters of water-flooded layer and undisturbed formation resistivity. This method has been used in evaluation of the water-flooded layers of a conglomerate reservoir in the Karamay Oilfield and achieved good results, improving the interpretation accuracy and compliance rate. It will provide technical support for avoiding perforation of high water-bearing layers and for adjustment of developmental programs.

Subtle trap recognition based on seismic sedimentology — A case study from Shengli Oilfield

Seismic sedimentology is the study of sedimentary rocks and facies using seismic data. However, often the sedimentary body features can’t be described quantitatively due to the limit of seismic resolution. High resolution inversion offsets this limitation and is applied to seismic sedimentology to identify subtle traps under complex geologic conditions, thereby widening the applicable range of seismic sedimentology. In this paper, based on seismic sedimentology, seismic phase-controlled nonlinear random inversion is used to predict the sandy conglomerate reservoir of Es3 in the Chezhen depression in Shengli Oilfield. Thickness and sedimentary microfacies maps of sandy conglomerate bodies in several stages are presented and several subtle traps were predicted and verified by drilling.

History of the Newark East field and the Barnett Shale as a gas reservoir

David Martineau is a certified petroleum geologist and received his B.S. degree in geology from the University of Texas in 1960. He joined Pitts in 1972 and is the exploration manager. Pitts has been involved in the Barnett play since its inception. Prior to Pitts, he worked for Prudential Drilling Funds and Coastal States Gas Producing Company (now El Paso). In 2006, the Newark East field was the largest producing gas field in Texas, and according to the Energy Information Administration (EIA) latest reserves estimate (EIA, 2006, tables B2 and B4), Newark East field ranks third in the nation and second in the nation in terms of production. The Newark East field has generated considerable attention because the gas is produced from the Barnett Shale as opposed to conventional sandstone, conglomerate, or carbonate reservoirs. The field was discovered in 1981 by Mitchell Energy Corporation (MEC) in Wise County, Texas, located in the Fort Worth Basin in north central Texas. George Mitchell, founder and chief executive officer of MEC, had the vision and leadership behind MEC's continued exploration and research for the correct technology to extract gas from this unconventional gas reservoir. Dan Steward was the chief geologist for MEC during the critical exploration development of the Barnett Shale and was honored by AAPG with the 2007 Outstanding Explorer Award. The development of the field started slowly, and only 100 wells were completed between 1981 and 1990. In 1998, a major breakthrough in completion technique occurred when water fracturing replaced gel fracturing. From 1997 to 2006, more than 5829 wells were put on production, and hundreds of additional wells were drilled, completed, or waiting on a pipeline. The field has been divided into two areas: (1) the original core area, where the Barnett sits on top of the Viola Limestone, …

Foreword -- Marine Conglomerate Reservoirs: Cretaceous of Western Canada and Modern Analogues

ABSTRACT This two-part special issue of the Bulletin of Canadian Petroleum Geology evolved from a technical session on Marine Conglomerate Reservoirs at the 2002 CSPG Diamond Jubilee Convention. The session was highlighted by eight oral and three poster presentations, seven of which formed the basis for manuscript contributions. The intent of the original technical session, as well as this subsequent special two-part publication, was to assemble a collection of targeted presentations covering a spectrum of topics relevant to hydrocarbon exploration in conglomerate reservoirs of marine origin in the Western Canada Sedimentary Basin. The majority of these conglomeratic units are natural gas reservoirs that comprise the backbone of the Deep Basin's productivity, and include some of the most prolific gas horizons in all of western Canada. From a global perspective, reservoirs of this geological nature and origin are relatively unique, if not rare. However, they are not uncommon in the Cretaceous of Alberta and British Columbia. Some, such as the Cardium and Viking formations, have been the focus of numerous studies, geological investigations and exploration drilling. However, for those conglomerate reservoirs of shallow marine origin within the Deep Basin, there has been little published work made available since the landmark AAPG Memoir 38 publication of Masters (1984). This lack of current information in the public domain, coupled with the recent completion of several relevant University theses and industry funded geological investigations, provided the impetus for the editors to compile these publications. This two-part publication was designed to be broad in its scope, and as such provides a multi-disciplinary approach to the investigation and prediction of shallow marine conglomerate reservoir facies. Topics range from sedimentary processes and geomorphology of modern day graveliferous shorelines to the sedimentological, stratigraphic and ichnological analyses of conglomerates in outcrop and subsurface. Of greatest and most immediate practicality to the geoscientist involved in the exploration of conglomerate reservoirs, are the regional subsurface investigations of natural gas bearing horizons from the Deep Basin. However, we remind our industry colleagues that while time is almost always of the essence in the oil and gas business, the non-immediately applied investigations published in this two-part publication, or any other of a similar bent, provide the building blocks and tools to understanding the internal architecture and prediction of conglomerate reservoirs in general. It is for these reasons, that these publications provides a collection of both recent results from University research and industry work as well as summary articles of investigations of gravel and conglomerates of shallow marine origin. For reasons of efficiency and cost, the special publication has been divided into part one (December, 2003) and part two (March, 2004). The two-part publication includes fivetopical headings discussed below.

Exploration potential of the Falher G shoreface conglomerate trend: evidence from outcrop

ABSTRACT The lower Cretaceous Falher Member shoreface conglomerate trends are the most prolific natural gas reservoirs of the Alberta and British Columbia Deep Basin. Individual pools can be in excess of 100BCF with discovery wells yielding AOFs of more than 100 MMCFD. Since the 1980s, five conglomerate shoreface trends (Falhers A, B, C, D and F) have been successfully drilled and mapped in the subsurface through observations of cores, cuttings, and well logs. Subsequent to their initial discovery and drilling in the subsurface each trend has been correlated to an outcrop equivalent in the Rocky Mountain Front Ranges of northeastern British Columbia. Until recently, no other Falher conglomerate shorelines have been recognized. South (paleolandward) of the Falher A-F trends, an older shoreface conglomerate fairway, designated the Falher G, has been discovered through outcrop observations at Holtslander Ridge near Belcourt Creek, British Columbia, 110 km southeast of the southernmost described Falher shoreface conglomerate outcrop. This trend, which is oriented oblique to younger trends, can be extrapolated into the subsurface plains at the Narraway Field, Alberta, approximately 35 km south of the nearest (Falher F) shoreline conglomerate reservoir fairway. Detailed analyses of measured sections, gamma log profiles, and photo mosaics show that the Falher G is a prograding shoreface facies association of clast-supported and sand matrix chert pebble conglomerate 8 to 12 m thick. The outcrop is approximately 5.0 km in length, along a north-south-trending depositional dip exposure that grades basinward from clast B supported conglomerate to pebbly sandstone. The Falher G shoreface outcrop contains several internal ravinement surface that dip at 5-10° to the NNW (320°). Analysis of locally available coal exploration core limits the paleoshoreline width of the Falher G conglomeratic shoreface trend to less than 5.0 km, with a paleoshoreline orientation of 285°/105°. Extrapolation of this trend into the subsurface may yield a new and significant shoreface conglomerate reservoir. 1 Also at: Department of Geology and Geophysics. University of Calgary, 2500 University Drive NW, Calgary, AB T2N IN4 End_Page 23-------------------------

Facies succession, stratigraphic occurrence, and paleogeographic context of conglomeratic shorelines within the Falher "C", Spirit River Formation, Deep Basin, west-central Alberta

The Falher “C” is a Lower Cretaceous transgressive-regressive sequence that contains mixed coarse-grained sandstone and conglomerate gas reservoirs in the Deep Basin of west-central Alberta. A total of 11 facies were identified in cored intervals of the Falher “C” and are further grouped into five facies associations representative of deposition in an offshore-marine through continental spectrum. Coarse-grained sandstone and conglomerate facies of high reservoir potential comprise facies association two (FA2), and were deposited within wave-dominated upper shoreface and foreshore settings. Finer grained non-reservoir facies (mudstone, siltstone, and fine-grained sandstone) were deposited within storm-dominated lower shoreface (FA1), tidal inlet (FA3), back-barrier (FA4), and coastal plain (FA5) environments. Several significant stratigraphic surfaces have been utilized to further sub-divide the Falher “C” into three parasequences termed C1, C2, and C3. In ascending order of stratigraphic occurrence these surfaces are defined as i) TSE1, ii) RSE, and iii) TSE2. The lower and upper contacts of conglomerate-rich parasequence C2 correspond to a regressive surface of marine erosion (RSE), and the youngest transgressive surface of marine erosion (TSE2). From correlations made between cored intervals and calibrated well logs, it can be recognized that reservoir-quality conglomerates are stratigraphically restricted to Twp. 67. A paleogeographic model constructed for the Falher “C” demonstrates the distribution of important environments of deposition at four consecutive depositional intervals corresponding to distinct changes in sea level and sediment supply to the Falher shoreline. Initially, the shoreline underwent transgression in response to a relative rise of sea level whereupon parasequence C1 began to prograde northward. Transgression and progradation was followed by a relative fall of sea level and increased sediment supply that brought about a forced regression and deposition of the reservoir-bearing conglomeratic parasequence C2. Progradation of parasequence C3 was established shortly after a second period of transgression across the study area. Continued normal regression in response to progradation of parasequence C3 northward of the study area maintained aggradation of coastal-plain and deposition of the capping nonmarine C4 unit. The results of this study serve to enhance our present understanding of the scale, distribution, and three-dimensional predictability of conglomerate gas reservoirs in the Deep Basin of Alberta.

Foreword -- Marine Conglomerate Reservoirs: Cretaceous of Western Canada and Modern Analogues

Research Article| December 01, 2003 Foreword — Marine Conglomerate Reservoirs: Cretaceous of Western Canada and Modern Analogues T. F. Moslow; T. F. Moslow Midnight Oil and Gas Ltd., 1000, 140 - 4 Avenue SW, Calgary, AB T2P 3N3, tmoslow@midnightoil.ca Search for other works by this author on: GSW Google Scholar John-Paul Zonneveld John-Paul Zonneveld Geological Survey of Canada, 3303 - 33 Street NW, Calgary, AB T2L 2A7, jzonneve@nrcan.gc.ca Search for other works by this author on: GSW Google Scholar Bulletin of Canadian Petroleum Geology (2003) 51 (4): 367–369. https://doi.org/10.2113/51.4.367 Article history first online: 02 Mar 2017 Cite View This Citation Add to Citation Manager Share Icon Share Facebook Twitter LinkedIn MailTo Tools Icon Tools Get Permissions Search Site Citation T. F. Moslow, John-Paul Zonneveld; Foreword — Marine Conglomerate Reservoirs: Cretaceous of Western Canada and Modern Analogues. Bulletin of Canadian Petroleum Geology 2003;; 51 (4): 367–369. doi: https://doi.org/10.2113/51.4.367 Download citation file: Ris (Zotero) Refmanager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex toolbar search Search Dropdown Menu toolbar search search input Search input auto suggest filter your search All ContentBy SocietyBulletin of Canadian Petroleum Geology Search Advanced Search This two-part special issue of the Bulletin of Canadian Petroleum Geology evolved from a technical session on “Marine Conglomerate Reservoirs” at the 2002 CSPG Diamond Jubilee Convention. The session was highlighted by eight oral and three poster presentations, seven of which formed the basis for manuscript contributions. The intent of the original technical session, as well as this subsequent special two-part publication, was to assemble a collection of targeted presentations covering a spectrum of topics relevant to hydrocarbon exploration in conglomerate reservoirs of marine origin in the Western Canada Sedimentary Basin. The majority of these conglomeratic units are natural gas... You do not have access to this content, please speak to your institutional administrator if you feel you should have access.

Use of 3D digital analogues as templates in reservoir modelling

Geological analogues may be used to rigorously interpret three-dimensional (3D) subsurface reservoir geometry by combining the capabilities of graphics workstations with digital outcrop data collection. Digital data from sedimentary environments and outcropping geological formations are interpreted in a 3D viewing environment to construct 3D templates of analogues for reservoir bodies. These 3D geometries and associated scaling parameters are then available to build 3D digital hypotheses concerning subsurface reservoir geometries. Two examples serve to illustrate this approach. Data from a modern fluvial system in the USA are used to construct digital templates. Interpretation of this dataset enables the relationship between 3D external geometries of sedimentary units to be rigorously defined and related to internal sedimentary structures. The location of gas-filled reservoir compartments in the Carboniferous Bend Conglomerate reservoirs of the Boonsville Field in North Texas are then interpreted using such analogue-derived digital templates.

Use of 3D digital analogues as templates in reservoir modelling

Geological analogues may be used to rigorously interpret three-dimensional (3D) subsurface reservoir geometry by combining the capabilities of graphics workstations with digital outcrop data collection. Digital data from sedimentary environments and outcropping geological formations are interpreted in a 3D viewing environment to construct 3D templates of analogues for reservoir bodies. These 3D geometries and associated scaling parameters are then available to build 3D digital hypotheses concerning subsurface reservoir geometries. Two examples serve to illustrate this approach. Data from a modern fluvial system in the USA are used to construct digital templates. Interpretation of this dataset enables the relationship between 3D external geometries of sedimentary units to be rigorously defined and related to internal sedimentary structures. The location of gas-filled reservoir compartments in the Carboniferous Bend Conglomerate reservoirs of the Boonsville Field in North Texas are then interpreted using such analogue-derived digital templates.

Modeling multisegmented hydraulic fracture in two extreme cases: No leakoff and dominating leakoff

Hydraulic fracturing is a necessary production enhancement procedure for low permeable conglomerate reservoirs. To study the hydraulic fracture (HF) propagation mechanism in strong heterogeneous conglomerate reservoirs, a numerical simulation based on the modified global cohesive zone method (CZM) was proposed. Two types of geological conglomerate models were built, and natural fractures were also considered in each model. A comprehensive discussion of the treatment parameters for the fracture geometry and width was also conducted. Numerical simulations suggest that a zig-zig fracture can be formed in all cases, while micro fractures emerge near the main fracture, and the number of micro fractures is larger for the composite gravel model than for the single gravel model. The presence of stiff gravel can affect the fracture propagation path and the associated conductivity and can sometimes result in an asymmetric fracture propagation path. The contribution effect of micro fracture on production might be debatable because of the relatively small fracture width. Four different mechanical behaviors, namely, penetration, deflection, attraction and termination, can be observed. In addition, fracture penetration tends to occur near the wellbore zone, while fracture branching generally occurs at the HF tip. The number of fracture deflection modes dominates the fracture behavior regardless of the distance between the HF and the gravel. The in situ stress condition determines the overall fracture propagation path, but the fracture starts to deviate under a low principal stress difference. An increase in the pump rate controls the fracture length due to a sufficiently large fluid injection volume. The increase in fracturing fluid viscosity does not affect the fracture geometry to a large extent but can heavily arrest fracture closure, thus improving fracture width, which can mitigate the large fracture width reduction along the gravel edge. Compared to the homogeneous rock model, the numerical simulation based on the adopted CZM method can be from a more complex fracture type with the conglomerate model, while numerical results can be validated by the triaxial fracturing simulation in the whole and local areas, which demonstrates the ability to perform a numerical simulation of HF propagation in reservoirs with strong heterogeneity.

Abstract: Application of Probe Permeametry, CT-scanning and Petrographic Image Analysis to the Understanding of Petrophysical and Pore Geometry Properties: Carmopolis Conglomerate Reservoirs, Sergipe-Alagoas Basin, Northeastern Brazil 

Abstract: Application of Probe Permeametry, CT-scanning and Petrographic Image Analysis to the Understanding of Petrophysical and Pore Geometry Properties: Carmopolis Conglomerate Reservoirs, Sergipe-Alagoas Basin, Northeastern Brazil 

Boonsville 3-D data set

The Bureau of Economic Geology at The University of Texas at Austin is making a 3-D seismic data set publicly available as part of the technology transfer activities of the Secondary Gas Recovery (SGR) program funded by the Gas Research Institute and the U.S. Department of Energy. The data are a significant part of the total data base amassed during a two‐year study of the Bend Conglomerate reservoir system in Boonsville Field in north‐central Texas.

High-Resolution Reservoir Characterization of Midcontinent Sandstones Using Wireline Resistivity Imaging, Boonsville (Bend Conglomerate) Gas Field, Fort Worth Basin, Texas: ABSTRACT

In the absence of abundant core data, Formation MicroScanner* (FMS) and Fullbore Formation Microlmager* (FMI) wireline logs from 3 wells in Boonsville Field provided continuous geologic information in a 1000-foot thick, Pennsylvanian (Atoka) interval. Cores provided the most detailed sequence-stratigraphic information, but only 358 ft of core from 4 wells was available to evaluate the 30 mi[sup 2] project area. The FMS and FMI logs thus served as continuous, oriented [open quote]virtual cores[close quote] that expanded our stratigraphic database and improved our interpretations, which included the identification of key chronostratigraphic surfaces, lithofacies, sedimentary structures, faults, and fractures. Paleocurrents inferred from the FMS and FMI images suggest that most Bend Conglomerate sandstones are lowstand valley-fill deposits derived from the Muenster and Red River Uplifts, rather than Ouachita-derived deltas. Combined analysis of cores and wireline resistivity imaging technology enabled the development of a fine-scale, sequence-stratigraphic framework which formed the basis for correlation and mapping of the major Bend Conglomerate reservoir zones, and helped us to identify compartmentalization mechanisms within these complex reservoirs.

Sedimentology and Permeability Architecture of Atokan Valley-Fill Natural Gas Reservoirs, Boonsville Field, North-Central Texas: ABSTRACT

ABSTRACT The Boonsville gas field in Jack and Wise Counties comprises numerous thin (10-20 ft) conglomeratic sandstone reservoirs within an approximately 1,000-ft-thick section of Atokan strata. Reservoir sandstone bodies commonly overlie sequence-boundary unconformities and exhibit overall upward-fining grain-size trends. Many represent incised valley-fill deposits that accumulated during postunconformity base-level rise. This stratal architecture is repeated at several levels throughout the Bend Conglomerate, suggesting that sediment accumulation occurred in a moderate- to low-accommodation setting and that base level fluctuated frequently. The reservoir units were deposited by low-sinuosity fluvial processes, causing a hierarchy of bed forms and grain-avalanche bar-front processes to produce complex grain-size variations. Permeability distribution is primarily controlled by depositional factors but may also be affected by secondary porosity created by the selective dissolution of chert clasts. High-permeability zones (-2.8 darcys) are characterized by macroscopic vugs composed of clast-shaped moldic voids (-5 mm in diameter). Tight (low-permeability) zones are heavily cemented by silica, calcite, dolomite, and ankerite and siderite cements. Minipermeameter, x-radiograph, and petrographic studies and facies analysis conducted on cores from two Bend Conglomerate reservoirs (Threshold Development Company, I. G. Yates 33, and OXY U.S.A. Sealy C 2) illustrate the hierarchy of sedimentological and diagenetic controls on permeability architecture. End_of_Record - Last_Page 758-------

Mid-Continent Natural Gas Reservoirs and Plays

Natural gas reservoirs of the mid-continent states of Oklahoma, Kansas, and Arkansas (northern part) have produced 103 trillion cubic ft (tcf) of natural gas. Oklahoma has produced the most, having a cumulative production of 71 tcf. The major reservoirs (those that have produced more than 10 billion ft[sup 3]) have been identified and organized into 28 plays based on geologic age, lithology, and depositional environment. The Atlas of Major Midcontinent Gas Reservoirs, published in 1993, provides the documentation for these plays. This atlas was a collaborative effort of the Gas Research Institute; Bureau of Economic Geology. The University of Texas at Austin; Arkansas Geological Commission; Kansas Geological survey; and Oklahoma Geological Survey. Total cumulative production for 530 major reservoirs is 66 tcf associated and nonassociated gas. Oklahoma has the highest production with 39 tcf from 390 major reservoirs, followed by Kansas with 26 tcf from 105 major reservoirs. Most of the mid-continent production is from Pennsylvanian (46%) and Permian (41%) reservoirs; Mississippian reservoirs account for 10% production, and lower Paleozoic reservoirs, 3%. The largest play by far is the Wolfcampian Shallow Shelf Carbonate-Hugoton Embayment play with 25 tcf cumulative production, most of which is from the Hugoton and Panoma fieldsmore » in Kansas and Guymon-Hugoton gas area in Oklahoma. A total of 53% of the mid-continent gas production is from dolostone and limestone reservoirs; 39% is from sandstone reservoirs. The remaining 8% is from chert conglomerate and granite-wash reservoirs. Geologically based plays established from the distribution of major gas reservoirs provide important support for the extension of productive trends, application of new resource technology to more efficient field development, and further exploration in the mid-continent region.« less

Three Levels of Compartmentation within the Overpressured Interval of the Anadarko Basin

Deep basin pressure compartments can be classified on the basis of their size, stratigraphy, and pressure regimes. Detailed investigations of the geologic setting and pressure gradients of numerous reservoirs in the Anadarko basin reveal the presence of three distinct levels of compartmentation. Level 1 is a basinwide feature known as the megacompartment complex (MCC). This complex is an overpressured volume of rocks that is completely enclosed by seals. It is approximately 241 km (150 mi) long, 113 km (70 mi) wide, and has a maximum thickness in excess of 4877 m (16,000 ft). Gas reserves of the overpressured reservoirs within the MCC are speculated to be approximately 20 tcf. The other two compartmentation levels are further subdivisions of the internal volume of the MCC. Level 2 compartmentation consists of multiple, district-, or field-sized configurations within a particular stratigraphic interval. These compartments are 32 to 49 km (20 to 30 mi) long, 19 to 32 km (12 to 20 mi) wide, and 122 to 183 m (400 to 600 ft) thick. Their reserve estimates can exceed 2 tcf. Examples of this type are the upper Morrowan Chert Conglomerate reservoirs in the Cheyenne/Reydon field area. Level 3 consists of a single, small field or a particular reservoir nested within Level 2. These compartments are generally 3 to 6 km (2 to 4 mi) long, The hierarchical classification of compartments has important implications for petroleum exploration and development. Recognizing the upper and lower boundaries of the MCC is essential to safe drilling practices. The similar pressures within Level 2 compartments allow the prediction of approximate reservoir pressures across trend-size areas of the basin (tens to

Synergistic Evaluation of a Complex Conglomerate Reservoir for EOR, Barrancas Formation, Argentina

Summary An engineering/geological study of the Top Red Conglomerate (TRC) section of the Barrancas formation, Mendoza area, Argentina, was conducted (1) to evaluate historical waterflood performance and recovery efficiency and (2) to develop a reservoir description and predictive model for later use in evaluation of reservoir response to EOR process applications. Original oil in place (OOIP) in the TRC reservoir was about 400 million STB [616 ⨯ 10–6 stock-tank m3]. The field had produced about 154 million STB [24.5 ⨯ 10–6 stock-tank m3] or 38.5% OOIP through 1980 and is under consideration for application of a caustic flooding EOR process. The TRC shows extremely large variations in permeability, both areally and vertically, owing to its origin as the uppermost part of a thick, alluvial fan, braided channel sequence of sediments. Porosity and permeability development in these rocks is governed primarily by the abundance of detrital clays. Reservoir quality also is reduced somewhat in localized areas by the presence of calcite and zeolite cements and by authigenic clays. An abundance of chemically reactive minerals in the formation poses a significant potential for formation damage and/or adverse reactions with injected EOR chemicals. A geological description of layering and areal variability in the reservoir was developed and used to guide the application of a black oil simulator to two cross-sectional models. Simulation of waterflood performance indicated good vertical sweep efficiency near injection wells, with less efficient sweep farther away owing to gravity segregation and an adverse mobility ratio. A preliminary screening and feasibility study evaluated several EOR processes for recovering the oil left after waterflooding. Caustic flooding appeared to be the most feasible EOR process for application in this reservoir. The mineralogy, chemical reactivity, and cation exchange capacity (CEC) of representative core samples were examined as a part of the EOR feasibility screening. The understanding of reservoir performance, distribution of remaining oil in place, reservoir heterogeneity, and chemical reactivity of the formation obtained during this study provided the basis for a reservoir model to be used in subsequent predictions of performance under EOR operations. Introduction The Mendoza contract area operated by Argentina-Cities Service Development Co. is about 50 miles [80 km] southeast of the city of Mendoza in the Cuyo basin of western Argentina (Fig. 1). The major producing formation in this study is the TRC interval of the Juro-Cretaceous Barrancas formation. The Punta de las Bardas (PB), Vacas Muertas (VM), and Gran Bajada Blanca (GBB) fields are contiguous and form a single, common reservoir in the TRC. Fig. 2 gives the stratigraphic nomenclature in the area. Development of the TRC reservoir began in 1959. The field produced under primary depletion, assisted by a natural water drive, until 1967, when it was recognized that the natural water drive was not strong enough to sustain continued fluid withdrawal from the reservoir. At this point, a pressure-maintenance program was implemented by injecting water into most of the wells located near the original water/oil contact. Individual well production performance has been controlled primarily by sand quality, structural location, completion intervals, and proximity to local permeability barriers in the reservoir. Material balance calculations indicate that the aquifer is of only limited influence in reservoir pressure maintenance. The initial pressure in the TRC reservoir was about 2,600 psi [17.93 MPa]. The pressure declined to a minimum of about 850 psi [5.86 MPa] by 1967–68, and then increased as a result of water injection pressure maintenance. The current reservoir pressure is about 1,500 psi [10.34 MPa]. Fig. 3 shows a waterfront advance map superimposed on a structure contour map of the TRC reservoir. The waterfronts shown represent advancement of a 40% water-cut front through time. The map shows that water advancement has been controlled by the structural configuration of the reservoir and by the presence of permeability barriers, particularly the large area near the center of the reservoir where the TRC interval is missing. It is unclear whether this area resulted from erosion of the TRC or from nondeposition; however, it does form an effective local barrier to water influx. JPT P. 295^

Geologic and Economic Significance of the Upper Morrow Chert Conglomerate Reservoir of the Anadarko Basin

The Upper Morrow chert conglomerate is recognized and described for its geologic significance as a new stratigraphic unit and for its economic significance as a reservoir, which has prompted the current deep drilling activity in the Anadarko basin of Texas and Oklahoma. Introduction The Upper Morrow chert conglomerate is a previously unrecognized stratigraphic marker and is one of the most significant gas reservoirs in the western Anadarko basin. It continues to be the object of a widespread exploratory effort in Hemphill and Wheeler counties in Texas and in Roger Mills, Beckham, and Washita counties in Oklahoma. These counties sit astride the axis of the basin and are near the Amarillo-Wichita mountain front (Fig. 1). Drilling to depths greater than 16,000 ft (4900 m) sometimes is required to reach these elusive stratigraphic traps; therefore, knowledge of the depositional environment of these Lower Pennsylvanian Morrow chert conglomerates is necessary to reduce exploratory risk. These chert conglomerates seem to fit a fan delta model, with elongate distributary channels carrying coarse sediments into a shallow marine environment.The reservoir usually is overpressured in the deeper part of the basin and may have a reserve of 1 Bcf/ft (93 million m3/m) of effective porosity on the 640-acre (2.59-km2) drilling unit. Pay thickness may exceed 50 ft (15 m), and deliverabilities of 10 MMcf/D (283 000 m3/d) are not uncommon.Before the discovery of the Shreikey field in Roberts County, TX, in 1974, little was known about the Upper Morrow chert conglomerates except from cores on one or two wells in Hemphill and Roberts counties, TX. Since the Shreikey discovery, this zone has prompted much of the deep exploratory drilling in the basin, with successful efforts in fields such as Buffalo Wallow, Reydon, Cheyenne, Elk City, and in recent discoveries. Regional Setting The Anadarko basin covers an area of approximately 35,000 sq miles (90 000 km2) stretching across northwestern Oklahoma, the northeastern Texas Panhandle, southwestern Kansas, and southeastern Colorado. The Morrow chert conglomerates are confined to a relatively small area in the eastern Texas Panhandle and western Oklahoma (Fig. 2). The basin is asymmetrical with its short limb and axis adjacent and parallel to the northwest-southeast trending Amarillo-Wichita uplift. This leads to an easy subdivision into mountain front, basin axis, and shelf area.Major orogenic movements occurred in late Devonian, post-Mississippian/pre-Morrowan, and post-Morrowan/pre-Des Moinesnian time, with the latter episodes producing most of the tectonic features of the area, including uplift, folding, and erosion of the Amarillo-Wichita Mountains and frontal area. The axes of faulted anticlines trend subparallel to the major uplift. JPT P. 489＾

Predicting Reservoir Rock Geometry and Continuity in Pennsylvanian Reservoirs, Elk City Field, Oklahoma

A geological-petrophysical engineering study of sandstone and conglomerate reservoirs was made to characterize and map pore-space distribution and to help predict fluid flow response of a waterflood. Floodable sand volume is believed to be represented accurately by net permeable sand isopach maps prepared from sand genesis knowledge. prepared from sand genesis knowledge. Introduction Detailed knowledge of the distribution of pore space and barriers influencing fluid flow combined with reservoir engineering data is critical for selecting, planning, and implementing operationally sound supplementary recovery projects. Reservoir engineers have recognized for many yearn that sandstone reservoirs are not homogeneous or simply layered. However, reservoir analyses commonly do not account adequately for the inhomogeneities or variations in reservoir and nonreservoir rock properties because these variations are not always defined accurately. The increasing understanding of sand-body genesis - how sands are deposited - makes possible accurate delineation of the spatial distribution of possible accurate delineation of the spatial distribution of pore space and barriers and helps significantly in pore space and barriers and helps significantly in predicting performance. This paper shows how the knowledge predicting performance. This paper shows how the knowledge of sand genesis can be used to provide an accurate picture of the reservoir rock system and insight into reservoir performance. This paper is based on a detailed performance. This paper is based on a detailed geological and petrophysical study of sandstone and conglomerate reservoirs and associated nonreservoir rocks in a plus or minus 500-ft-thick interval in the Elk City field, a 100-million-bbl field in the Anadarko basin in south-western Oklahoma (Fig. 1). The paper describes (1) the reservoir rock characteristics of the genetic sand-body types that make up the reservoirs, (2) the geometry and continuity of the pore space and barriers to fluid flow, and (3) most useful maps for portraying floodable pay and predicting performance. The study was conducted during the time of declining primary production and while a waterflood was being planned. The Elk City field produces from Pennsylvanian sandstones and conglomerates interbedded with nonproductive siltstones, shales, and carbonates. The interval studied includes the L and M zones, the two major reservoirs (Fig. 2). The field is an anticline developed by 3 10 wells on 40-acre spacing covering about 25 sq miles. Fig. 3 is a structure map on the dense marine limestone marker, Marker M, that separates the L and M zones. Data Control Most of the 310 wells were logged with a combination of SP log, 8- and 16-in. normal resistivity log, 24-ft lateral log, and microlog. In 16 wells, a gamma-ray neutron log was run instead of the microlog. Cores representing more than 1,700 ft of interval from 26 wells were studied. Approach and Methods of Study The study was conducted in four interrelated parts:lithology and petrophysical properties of the cores were studied, and the logs were calibrated with lithology in the cored intervals;genesis of the reservoir and associated rocks was interpreted;correlation was established; andthe interval was divided into subzones, and the net sand and sequences of rock types were mapped for each subzone. P. 851

Estimation of Well Permeability for Use in Single Phase Gas Reservoir Production Simulation

Of all of the reservoir data necessary for use in mathematical reservoir simulation, the permeability value is usually the least known and most difficult to obtain. A previously published correlation has been used in estimating permeability values for wells in a tight, single phase gas reservoir. These values were used in a mathematical model, along with other better known reservoir data, to match past performance and predict future performance of individual wells. predict future performance of individual wells. Reasonably satisfactory results were obtained with a minimum number of runs. Computer time is believed to be considerably less than that which would have been required if the correlation had not been available. There are several occasions when permeability values can be successfully estimated for simulation projects without benefit of individual well core projects without benefit of individual well core analysis or pressure test permeability data. The method described here involved use of a correlation presented as Fig. 2 (see Fig. 1) in paper SPE 1555 by L. E. Harlan. It is a log-log plot of adjusted absolute open flow, times 1,000, divided by initial shut-in tubing pressure squared vs known productive capacity (Keh) pressure squared vs known productive capacity (Keh) for 22 gas wells. The 22 data points are from "skin free" wells in carbonate, sand, and conglomerate reservoirs in four basin areas in the U. S. The paper describes adjusted absolute open flow as a well's calculated wellhead absolute open flow potential based on test data after 1 year of production. Justification for construction and application of the correlation is contained in the paper and will not be discussed here. The correlation was used in this study for estimating productive capacity (Keh) for 25 wells in the 2,033-well Blanco Mesaverde gas field in Northwest New Mexico. Adjusted absolute open flow for the wells was calculated from the New Mexico Oil Conservation Commission deliverability test taken 12 to 24 months after a well was placed on production. Permeability was obtained from the correlation-derived Permeability was obtained from the correlation-derived productive capacity through application of net productive capacity through application of net effective pay for a particular well. In the simulation work, predicted capacity was compared with actual capacity at a particular cumulative production point. For nearly all of the wells modeled, a satisfactory match was achieved without necessity of changing permeability. P. 1389