Vertical Permeability Barriers Research Articles

Facies analysis and petrophysical investigation of the Late Miocene Abu Madi sandstones gas reservoirs from offshore Baltim East field (Nile Delta, Egypt)

The Nile Delta has become an economically important region of Egypt, because of large-scale natural gas and oil discoveries in recent decades. The offshore Baltim East field is one of the Nile Delta's major gas producers from the upper Miocene clastic reservoirs, but detailed lithofacies and petrophysical analyses of the Abu Madi gas reservoir have not been conducted to date. This study investigates the petrographical and petrophysical properties of the upper Miocene Abu Madi Formation from the Nile Delta to infer the lithofacies distribution, depositional environments, and reservoir qualities of the Level 3 Main and Lower sands. In this work, we used a variety of data sets, including core samples, petrophysical measurements, and well logs, to identify the most important characteristics of these sandstone reservoirs. Both reservoirs are hydrostatically pressured and exhibit a gas gradient of ∼2.26 MPa/km. We have identified six different lithofacies from the two reservoirs. SEM and thin section analyses indicate that trough cross-bedded (F-1), parallel laminated (F-2), and massive sandstones (F-6) are the primary reservoir lithofacies composed of texturally immature subfeldspathic quartz arenites. These sandstones have sharp bases and exhibit fining-upward trends with ripple laminated siltstone (F-3), heterolithic silt and clay (F-4), and laminated claystone (F-5) facies lying on top. We inferred the reservoir depositional environment as fluvial channels and sequence stratigraphically these incised valley-fills represent low stand systems tract. The reservoir sandstone facies show good porosity (10–28%), mostly interparticle. Chlorite coatings around quartz grains are abundant, while pore-filling kaolinite is the dominant porosity-destroying clay phase. Grain dissolution introduced secondary intergranular porosity along the potassium feldspar cleavage planes within the F-1 lithofacies. Porosity, permeability, and reservoir quality parameters (RQI, NPI, and FZI) calculated from routine core analysis indicate that the F-1 and F-6 lithofacies have excellent hydraulic flow properties with >100 mD permeability, RQI>1 μm and FZI >5 μm, while the fine-to very fine-grained F-2 offers poor to fair reservoir quality defined by a wide permeability range of 0.1–2150 mD. The clay and silt-dominated lithofacies (F-3, F-4, and F-5), due to their impervious nature, act as intra-reservoir vertical permeability barriers. The differences in rock composition and facies control diagenesis and physical properties of the reservoir. The results presented, provide further insight into the exploration of the fluvial channel deposits and regional reservoir quality of the upper Miocene Abu Madi Formation of the Nile Delta.

Towards a better understanding of the highly overpressured Lower Triassic Bunter reservoir rocks in the Terschelling Basin

Abstract Large lateral variations in pore-fluid pressures and associated overpressures occur in the compartmentalized Lower Triassic Bunter reservoir rocks in the Terschelling Basin (northern Dutch offshore). This study describes the main controlling factors on the distribution of these overpressures by combining seismically derived structural interpretations with pressure data. The most important controlling factor is considered to be the presence and type of both lateral and vertical permeability barriers. Lateral permeability barriers are formed by Zechstein salt and faults. The most effective vertical permeability barrier for maintaining high overpressures is the Upper Triassic Röt evaporite. Overpressures of more than 30 MPa are observed in the Bunter compartments where the Röt is present and laterally continuous. Overpressures are lower than 15 MPa in compartments where the Röt was affected by Mid-Cimmerian erosion. Based on structural observations, it is concluded that the highly overpressured compartments became fully hydraulically restricted during the Late Jurassic and Early Cretaceous. Calculations show that subsequent sedimentary loading, during the Cretaceous and Cenozoic, was able to generate the observed overpressures.

Production Optimization in the Campos Basin: A Case for Robustness in Waterflooding

This article, written by Editorial Manager Adam Wilson, contains highlights of paper OTC 22560, ’Production Optimization in a Campos Basin Reservoir: A Case for Applying Robustness Measures to a Waterflood Project from Subsurface and Operational Design to Execution,’ by Ozan Arslan, SPE, Kyle Koerner, SPE, Stephen Knapp, Nate Biddle, Alwin Bok, SPE, and Paulo Chaves, BP, prepared for the 2011 Offshore Technology Conference Brasil, Rio de Janeiro, 4-6 October. The paper has not been peer reviewed. A successful cross-discipline workflow used in a Campos basin multiproducer-system waterflood program encompassed subsurface characterization, well planning, data acquisition, well controls, and surveillance to support efficient oil recovery. Drilling from a central platform, extended-reach wells were necessary to access a structured series of near-shore, laterally amalgamated channel sands separated by variable barriers posing significant subsurface-modeling, well-design, and drilling challenges. A cross-discipline-team approach employed robustness measures to find a near-optimal solution with controlled risk management. Introduction The Polvo complex is a system of clastic (Upper Cretaceous) and Macae carbonate (Lower Cretaceous) reservoirs in the Campos basin with 18–22°API oil. The clastics have been on production for 3 years with natural waterdrive and water injection. Development drilling started in mid-2008 for the Cretaceous sand system (CSS) where wells were completed with openhole gravel packs and electrical submersible pumps. Robust waterflood design and execution require a proactive, risk-minimizing reservoir-management strategy. The team used a cross-discipline workflow to achieve a near-optimal performance in the Polvo C_3 reservoir (Fig. 1). The workflow ensured the communication of constraints and raised potential decision points for Reservoir characterization Numerical modeling and uncertainty assessment Well planning (constraints and data acquisition) Well completion (integrity and sustained injectivity) Operational issues and surveillance tactics Remediation and optimization Robustness of proposed solutions is particularly critical in terms of reservoir characterization where certain geological outcomes, such as fault transmissibility or sand/sand connectivity, can be discrete in nature (sealing or not sealing). Therefore, capturing key geological assumptions in the CSS and communicating the critical decision points and possible outcomes across the team played pivotal roles in the workflow. Reservoir Characterization and Waterflood Design Detailed descriptions from core data indicated that channels and lagoons are the primary depositional environments for these reservoirs. Analysis of all the data collected on the CSS reservoirs suggested uniform layering, where each sand-prone layer exhibits a high degree of internal lateral continuity. Each sand-prone interval is capped by a shale layer interpreted as a sea-level rise shifting the reservoir facies northwest. The vertical rise in sea level coupled with the local dip on the Macae surface will control the lateral offset distance of reservoir facies from layer to layer, which, in turn, affects the local vertical communication between reservoir layers. The expectation is that there will be vertical permeability barriers, at least locally.

Experimental and Simulation Studies of the Effect of Vertical Permeability Barriers on Oil Recovery Efficiency During Solvent Injection Processes

Almost all of the heavy oil reservoirs contain discontinuous permeability barriers (shales) with different structures. However, the effect of shaly layer geometrical characteristics including: spacing from wells, discontinuity, orientation, shaly layers' spacing and length, and heterogeneous distribution on oil recovery factor in the presence of gravity force are not well understood. In this work, a series of solvent injection experiments were conducted on various vertical one-quarter five-spot glass micromodels, containing barriers, which were initially saturated with a heavy oil sample. The oil recovery was measured by analysis of the pictures provided continuously during the injection processes. The experimental data were used for developing and validating a compositional-numerical model. The results indicated that the ultimate oil recovery in the presence of shales is lower than that in homogeneous models. The gravity force caused the solvent to be propagated better in the media. It was observed that the oil recovery is inversely proportional to the shaly structure's orientation with the main flow direction; by increasing the length of the shaly layers in the flow direction, the sweep efficiency decreased. However, with constant length, it was observed that the shaly layers' discontinuity results in higher oil recovery. The lower distance of these barriers from the production well reduced the final oil recovery, but it acted conversely for the case of the injection well. By increasing either the horizontal or vertical spacing between barriers or reducing the percent of the heterogeneously distributed shales, the recovery value improved.

Water-Jet Fracturing a Horizontal Openhole Completion

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 134855, ’Effectiveness of Water-Jet Fracturing on a Horizontal Openhole Completion: Case Study,’ by Sigifredo J. Rosales, SPE, Chevron, and Rafael A. Hernandez, Cynthia Yuen Lynch, and Ernesto Bustamante, SPE, Halliburton, prepared for the 2010 SPE Annual Technical Conference and Exhibition, Florence, Italy, 19-22 September. The paper has not been peer reviewed. Without proper isolation methods, the use of openhole horizontal-well fracturing is limited. During many fracturing processes, fracture or acid placement often occurs where fluid first contacts the borehole, usually at the heel of a horizontal well. A method that combines hydrajetting and fracturing techniques enables positioning a jetting tool at the precise point where the fracture is required, without the use of sealing elements. Multiple fractures can be placed in the well, spaced evenly or unevenly as prescribed by the fracture-design program. Introduction Water-jetting is a cold-cutting process that can be used for cutting or perforating holes in stone, glass, and metal. There are two basic types of water-jetting techniques: water-only jetting (hydrojetting) and abrasive water jetting (hydrajetting). Common applications for hydrajetting in the oil industry are cutting and perforating. Recent improvements in hydrajetting tools have made them more resistant to abrasive materials, significantly increasing tool life. With more-reliable tools, this technology can be used for well stimulation. The full-length paper details results from a stimulation treatment performed with the hydrajet fracture-stimulation technology in a horizontal openhole completion, executed in a low-permeability, high-porosity reservoir in the Antelope formation of the Monterey shales in the San Joaquin Valley of central California. Horizontal Openhole Stimulations Low-permeability zones often contain multiple layers with varying porosity and permeability. Unexpected vertical-permeability barriers that are too thin to detect with conventional well logs often exist. In low-permeability environments, horizontal openhole completions enhance reservoir contact, but there are challenges when designing stimulation treatments for this type of completion. Uncontrolled generation of hydraulically induced fractures normally results in poorly distributed fractures along an openhole lateral, of any length. For optimum production enhancement, a fracturing-stimulation program should produce a limited number of discrete fractures that are widely separated and well distributed along the horizontal section. The width and length of each fracture are reduced as the number of fractures increases. Another objective is to create fractures only where they are needed. Multiple close-proximity fractures will improve the initial stimulation response, but only for a short time following the treatment. High-rate large-volume open-hole fracturing-stimulation attempts in which fluid is bullheaded into the open hole typically result in extreme multiple fracturing that causes most of the treating fluid to be placed in one small part of the reservoir near the heel section, leaving the rest of the interval essentially untreated.

Quartz cementation in mudstones: sheet-like quartz cement from clay mineral reactions during burial

ABSTRACT Petrographic evidence of thin sheet-like or platelet-shaped quartz cement parallel to bedding is documented in deeply buried, originally smectite-rich, Late Cretaceous mudstones from well 6505/10-1 in the Voring Basin, offshore Norway. The platelets are mainly built up of areas of patchy continuous quartz cement with various amounts of earlier-formed interlocking microquartz crystals. Cathode luminescence (CL) spectra confirm an authigenic origin for the quartz cement. The quartz platelets may originate as flakes (at c . 90–100 °C) that may evolve into well-developed near-continuous patchy quartz cement identified at 4300 m/150 °C. The quartz cement is probably sourced from silica released by the clay dissolution-precipitation processes (smectite and smectite/illite to illite and kaolinite to illite). At temperatures above about 90–100 °C, the continuous supply of silica from these clay mineral reactions results in precipitation of quartz flakes and sheet-like quartz cement. The quartz sheets may act as a mudrock stiffening agent, reinforcing and further cementing together the microquartz networks and aggregates and possibly also enhancing the schistosity and anisotropy of these mudstones during increasing burial. The quartz sheets may also act as vertical permeability barriers in the sediment possibly contributing to overpressure formation during chemical compaction.

Formation evaluation of an onshore appraisal well ‘KG-5’, “green field”, Niger Delta, Nigeria

The Well KG-5 is a vertical well drilled to evaluate an exploration prospect in the onshore “Green Field” Niger Delta. It discovered a significant oil column within the sandstone reservoir intervals. A conventional suite of wireline logs including gamma ray, calliper, sonic, density, neutron, dual laterolog and micro-SFL resistivities were acquired for formation evaluation purposes. Also two cores were cut in the reservoir interval for hydrocarbon shows analysis. The result of the formation evaluation shows that reservoir zones Q-A and Q-B contain oil while reservoirs Q-C and Q-D are water filled. The contact between the oil and water (Oil water contact-OWC/Free Water Level) is at a depth of 2464m. The net pay porosity values range between 0.139v/v and 0.165v/v with an average of about 0.158v/v. The trends of the neutron-density crossplot and the Picket plot indicate that there is a little contribution of dispersed and laminated clays in the reservoir, which would have significantly affected the poro-perm values of the reservoir intervals. Also, the net pay water saturation (0.266v/v) is reduced as compared with the net reservoir saturation (0.434v/v). And out of 8.080 equivalent pore column (EPC), 5.935 are equivalent hydrocarbon column (EHC). Because the minor claystone beds within the reservoir sands are laterally continuous and may be vertical permeability barriers; the reservoir engineers should run a separate perforation for reservoirs Q-A and Q-B. This is because the two reservoirs may not be in vertical communication due to claystone baffles. And so hydrocarbon flow would be mainly horizontal.

Integrated approach to geomodelling and dynamic simulation in a complex mixed siliciclastic–carbonate reservoir, N'Kossa field, Offshore Congo

Abstract The Lower Sendji Carbonate (Albian age) of the N'Kossa field is a mixed siliciclastic–carbonate reservoir exhibiting very heterogeneous reservoir properties and the development of extensive vertical flow permeability barriers. The reservoir is a succession of interstratified dolomite, limestone, sandstone and shale lithologies of sabkha, tidal flat and lagoonal origin. Early, synsedimentary dolomite cements are extensively developed, particularly over local palaeohighs. Challenges to hydrocarbon production include: (1) the vertical variability of reservoir properties; (2) the presence of many, laterally extensive vertical flow barriers; and (3) variable connectivity between fault-bounded compartments. This complexity was underestimated at the appraisal stage, the initial development plan calling for a relatively simple scheme of pressure support to the critical reservoir fluid via injection into the gas cap and the water leg. This decision was supported by the identification of a single hydrocarbon column (>400 m thick) over the entire structure which suggested a lack of vertical compartmentalization. Recent studies, which include a geological synthesis of more than forty wells and a dynamic data synthesis to determine the production mechanism and identify key heterogeneities, show a lack of pressure support to the oil leg from both water and gas injector wells. Today, integration of static and dynamic data together with an improved geological understanding of the stratigraphic control on vertical flow barriers and mapping of high permeability sandstone layers is the key to identifying unswept zones of the field and future infill drilling targets.

Combining Continuous Fluid Typing, Wireline Formation Testers, and Geochemical Measurements for an Improved Understanding of Reservoir Architecture

Summary Identifying compartmentalization and understanding reservoir structure are of critical importance to reservoir development. Traditional methods of identifying reservoir compartmentalization, such as drillstem tests and extended well tests, often become impractical in deepwater settings, with costs approaching the costs of new wells and emissions becoming increasingly undesirable. Thus, compartments often have to be identified by some other means. Individual formation-pressure measurements, downhole fluid analysis (DFA), and geochemistry are known to provide important information about reservoir architecture. When these powerful methods are combined systematically and applied to data sets, the resulting synergy delivers a much more accurate and robust picture of the reservoir. In this paper, we review a number of case studies in which we have successfully combined continuous fluid/facies mapping, pressure-gradient measurements, DFA, and geochemistry for a reservoir-continuity assessment in a diverse range of geological settings, including a wide range of field sizes, structural environments, reservoir lithologies, and oil types. Particular emphasis is placed on comparing the strengths and limitations of the different techniques in revealing reservoir architecture, especially vertical-permeability barriers. We present a number of unambiguous cases, for which multiple data streams might be viewed as being somewhat redundant. More-ambiguous cases, in which the multiple data streams are required to make a robust assessment of key reservoir properties, are also presented.

Early to mid-Cretaceous mixed carbonate-clastic shelfal systems: examples, issues and models from the Arabian Plate

ABSTRACT Maximum Flooding Surfaces (MFS) in the Early to mid-Cretaceous mixed carbonate-clastic shelfal systems of the Arabian Plate have been incorporated into a new sequence stratigraphic model that links Kuwait, Iran, Saudi Arabia, Qatar, and the United Arab Emirates, to Oman and Yemen. It is based on regional sequence stratigraphic concepts supported by biostratigraphic, sedimentological and mineralogical data. The model has amended the positions of some existing MFS. The diachronous interplay between large-scale, proximal clastic systems and outboard (down-systems-tract) carbonate platforms was emphasized by concentrating on the depositional history of prodelta areas during delta advance and retreat. The prodelta area of relatively deep water separating the depositional systems has been termed the ‘Migratory Carbonate Suppressed Belt’ (MCSB). The model proposes that platform limestones expanded back over preceding prodelta areas during transgressions. The most extensive transgressions ultimately led to the demise of MCSBs. The maximum landward retreat of the shoreline coincided with the cessation of clastic input in the most up-systems-tract localities. Thus, the model has predicted that in many places MFS are located in the basal parts of clean carbonates even though these are not the deepest-water sediments. Examples are the Zubair-Shu’aiba (K70 MFS) and the upper Burgan-Maddud (K100) sections of the northern Gulf. Where carbonate platforms did not expand completely across the MCSBs, perhaps because of fault-control, the MCSBs survived and MFS are present within deeper-water, prodelta shales deposited below the most efficient window for carbonate production. Examples are the K40 to K60 MFS in intraformational shales of the Zubair, Biyadh, and Qishn formations of Kuwait, Saudi Arabia, and Yemen, and K100 in the Burgan-Wasia formations of Kuwait and Saudi Arabia. Even in these cases, the MFS are present within limestones deposited further down-systems-tract, notably in Iran (K60—Khalij Member, Gadvan Formation; K100—Dair Limestone Member, Burgan-Kazhdumi formations). Deeper-water dense limestones and shales with accompanying MFS were deposited along the northeastern passive margin of the Arabian Plate, or within intrashelf basins with some limited connection to the open ocean. From a regional perspective it can be seen that eustatic or tectonically forced MFS do not necessarily occur within the deepest-water facies. A regional understanding is needed for a more precise sequence stratigraphic interpretation of the Early to mid-Cretaceous succession of the Arabian Plate. The identification of the stratigraphic architecture is of major economic importance at the reservoir scale, for instance in recognizing vertical permeability and transmissibility barriers, as well as at the regional-play fairway scale in the distribution of seals and their potential influence on migration pathways. Our interpretations are also relevant to the prediction of source-rock distributions and, in the longer term, may help identify stratigraphic trap potential related to the interplay between clastic and carbonate depositional systems. Although the model proposed relates to the Arabian Plate, general conclusions may be applicable to other regions where mixed carbonate-clastic systems are well developed, for example in many basins of Tertiary age in South East Asia.

Combining Sequence Stratigraphy, Geostatistical Simulations, and Production Data for Modeling a Fluvial Reservoir in the Chaunoy Field (Triassic, France)

Reservoir modeling of the Chaunoy field was performed by combining a sedimentological study, a sequence stratigraphic analysis, geostatistical simulations, and the analysis of production data and fluid-flow simulations. The reservoir corresponds to the distal part of a Middle Triassic alluvial fan system in the Paris basin (France), and is extremely heterogeneous and layered. The reservoir mostly consists of small ribbon channel deposits interbedded with flood-plain and lacustrine mudstones. The channel amalgamation rate varied with cyclic lake-level variations, which directly controlled the reservoir geometry. Within a base-level cycle, during periods of low accommodation, channels were amalgamated, forming highly heterogeneous sand sheets. As the accommodation increased, channels became progressively isolated within flood-plain mudstones. Finally, a lacustrine transgression deposited lacustrine mudstones and induced thin but widespread vertical permeability barriers across the field. As accommodation started to decrease, considerable pedogenetic alteration occurred, as shown by dolocretes and groundwater dolomites. Five cycles that constituted the reservoir layering framework were identified. Geostatistical simulations of lithotype distribution within these units were computed using the truncated random Gaussian function method. Horizontal and vertical lithotype proportion curves and variograms were calculated from well data. Because of the wide well spacing, it was not possible to determine the range of horizontal experimental variograms. Three lithotype realizations were simulated within a high-resolution grid to compare short, medium, and long correlation lengths. After assigning petrophysical properties to the lithotypes and upscaling, fluid-flow simulations were performed for the three realizations. The three flow simulations were then compared to the 10-yr production history of the field. The simulations showed quite a good match regardless of the variogram range, except in the northern part of the field, indicating a problem in the reservoir layering in this area. This relative insensibility of the flow simulation to the correlation length probably is due to the high net pay within the amalgamated channel reservoir units and to the high number of conditioning wells; however, the flow simulation performed with the longest correlation length showed the best fit with the production history.

Unforeseen Geology Creates a Need For "an Integrated Team Effort In Geosteering a Horizontal Well to Success In Northwest Australia

Abstract West Australian Petroleum Pty. Limited has improved the prospects of further development of a mature oilfield on the, Northwest Shelf of Australia by utilizing horizontal well technology. Combining detailed reservoir characterization and MWD information, a well path initially intended to include 500m of near-horizontal section was redesigned during the course of drilling to adapt to unforeseen changesin the geology of the reservoir due to local faulting. The result was 959m in of horizontal section at 680 mTVD, 400 m of which were in productive interval. The well reached inclinations as high as 103 ° and turned through 30 ° azimuth to run parallel to the field'sbounding fault, transforming a potentially failed wellbore into a success through interactive geosteering. The problem-free drilling of this well has opened the way for newapproaches to developing this mature oilfield. Introduction West Australian Petroleum Pty. Limited (W APET) Operates the Barrow Island oilfield on the Northwest Shelf of Australia for its joint venture participants Chevron Asiatic Limited, Texaco Oil Development Company, Mobil Exploration and Developing Australia and Shell Development (Australia) Pty Ltd. Barrow Islandis located approximately 1,300 Ian north of Perth and 56 Ian off the mainland coast (Figure 1). The Island covers an area of 234 sq. Ian and forms the surface expression of a north-plunging regional anticline that has persisted since the Middle Jurassic. A large normal fault, referred to as the Barrow Fault, truncates the southern end of the anticline forming the southern limit of the trap (Figure 1). The Cretaceous Windalia Sand is the largest reservoir on Barrow Island; covering an area of about 90 sq. Ian, it has over 140 m of vertical closure from 560 to 700 m below sea level (Figure 1). Approximately 30 m thick, the Windalia Sand is subdivided into three main units: two reservoir intervals, the Upper and Lower Sands approximately 17 m and 9 m thick respectively, separated by a 4 m thick silty claystone unit referred to as the Middle Shale. The Upper and Lower Sands consist of fine grained, glauconitic shaly sand, and are further subdivided by thin carbonate cemented sands or tight streaks, typically less than 50 cm thick. Correlations indicate the tight streaks conform with the stratigraphy of the reservoir and are laterally extensive over parts of the field, forming localized vertical permeability barriers. Average porosities for the Upper and Lower Sands are approximately 24% and 21 %, while the average permeabilities are 8 md and 3 md. FIGURE 1. Illustrations Available In Full Paper. However, the better quality parts of the reservoir in both the Upper and Lower Sands have core porosities and permeabilities as high as 28% and 100 millidarcies. Reservoir quality is primarily dependent on the content of glauconite or other clays in the sands. Evaluated oil saturations exhibit a continuous transition from 50% at the crest of the anticline, to around 30% at the present limit of drilling on the flanks.

On The Performance Of Horizontal Wells In Reservoirs Containing Discontinuous Shales

Abstract To fully utilize the potential of horizontal wells, the well planning team must have a clear understanding of both vertical and lateral reservoir characteristics. In many instances, a major uncertainty is the degree to which the horizontal well productivity will be affected by the presence of discontinuous shales. Previous studies concerned with this problem have reported horizontal well productivity as a function of effective vertical permeability, which offers no direct indication of the effects of shale lateral extent, preferential orientation and vertical frequency on well performance. With a numerical model study and an explicit stochastic shale generation algorithm, the influence of shale frequency, size and areal alignment, with respect to the horizontal well direction, on the well productivity was systematically investigated. The result shows that for any given frequency, well productivity is not monotonically related to shale size. Owing to the inclined flow path to the horizontal well, a local minimum in productivity exists as the shale barriers increase in size. The orientation of the horizontal well with respect to the alignment of the shale bodies was found to influence well productivity. Additionally, the productivity of a shorter horizontal well was found to be less affected by the shale bodies. Finally, an empirical correlation based on simulation results is presented. The observations presented in this paper provide new insight into vertical reservoir characterization from horizontal well pressure data, as well as horizontal well planning in reservoirs with a known directional bias in sedimentary structures. Introduction The last decade witnessed a substantial increase in the activities of horizontal wells mainly due to advances in drilling technology which improved the economics of drilling horizontal wells. A horizontal well can typically produce reservoir fluids at a rate two to six times that of a vertical well. The productivity of horizontal wells depends largely on the vertical permeability of the formation. The constituents that reduce the vertical permeability of a reservoir are impermeable flow barriers, such as shales, distributed throughout the formation. Since shales are the most common type of vertical permeability barriers, the term "shales" is used in the remainder of this paper to designate all the impermeable reservoir facies. Through this study we make an attempt to quantify the effect of discontinuous shales on the productivity of horizontal wells. Two types of shale distributions affect fluid flow in the reservoir(1)- continuous shales and discontinuous shales. The shale barriers with known lateral extent and distribution within the formation are termed as continuous shales. Discontinuous shales are those which cannot be correlated between wells and are usually distributed randomly within the porous media. The spatial distribution and the dimension of the discontinuous shales cannot be determined accurately. In order to account for the uncertainty in their lateral extent and distribution within the reservoir, stochastic modelling techniques(2) are generally used to represent the discontinuous shale barriers in reservoir simulation models. There are two different ways to represent discontinuous shales in simulation models: explicit and implicit representation.

Lake Maracaibo Bachaquero Area, Bloque IV Field: A Sparse Logged Area with Additional Reserves?: ABSTRACT

The results of the high resolution logging throughout the Lagunillas Inferior reservoir, in the VLD-1112 and VLD 1152 wells in the Bloque IV area of Lake Maracaibo, Venezuela, are described in this work. Parts of the reservoir were previously overlooked due to the use of simple petrophysical evaluation using very sparse old logs ( SP, Gr, Res.) which show high water saturation`s ( Sw>0.5) and very low porosity`s (O <0.1). In the intervals with thin laminations, the use of microresistivity images define the clean sands of the shaly section, where pressure tests were taken. With these logs, was possible to define local vertical permeability barriers, which separate the productive well known high permeability zones from other zones which could represent additional reserves. A new sedimentological model was defined using core information and the high resolution microresistivity images, subdividing the reservoir into 12 layers, replacing the old simple 3 layer model. Open hole evaluation of the new wells and cased hole measurements using a saturation log indicate that gas has preferentially moved into high permeability zones, leading to bypassing of oil in moderate to low permeability layers. With this study the possible amount of oil which was overlooked by Maraven couldmore » be about 23 %, compared to the estimations derived from the simple petrophysical evaluation, in the shaly sands, which have a big impact in future completion programs . Finally these results were used to locate and drill the first horizontal well in Bloque IV area.« less

Petrophysical Evidence for the Nature of Vertical Permeability Barriers: Temple Ave. Fault, Wilmington Oil Field, Long Beach, California: ABSTRACT

The Temple Avenue fault is a north-trending east-dipping normal fault that dissects the north flank of the Wilmington anticline in the Wilmington Oil field. The fault involves sediments of the Repetto Formation (lower Pliocene) and the Puente Formation (upper Miocene). Oil/water contact structural maps indicate that the fault acts as a permeability barrier. Well B-756-I was drilled across the Temple Ave. fault in the Repetto Formation. The throw of the fault in this well ranges from 15 to 17 meters (50 to 56 feet). The Repetto Formation is composed of interbeded sands and shales. Sixty five samples were collected from and around the fault zone. Preliminary XRD analysis of bulk and clay fractions show that authigenic clay minerals (<2 [mu]m) represent between 1 to 2% of the sediments. Clay minerals are mostly smectite (5-7%) and a Fe-illite (15-30%); chlorite and kaolinite are also present. The authigenic illite content appears to increase around the fault zone. Diagenetic conversion of Ca-rich feldspars to smectite is suggested by an inverse correlation of their abundances. Calcite is present in the majority of the samples (4-8%), but a significant increase in the carbonate content (14-16%) occurs along the fault. Ongoing SEM and isotope analysis willmore » aid in the determination of the origin and nature of the changes in the mineralogy that contribute to form a permeability barrier.« less

Monobore Completions and Novel Wireline Perforating of High-Angle Wells in the Nelson Field

The Nelson field gas-lift completions were designed to optimize production, enhance safety and reliability, and minimize well-maintenance costs. The completions are of a near-monobore design and include an annular safety system, which is regarded as a major safety benefit during gas lift. The single-trip completions were batch installed in eight high-angle (up to 70{degree}) predrilled wells. This paper presents details of the completion design and the approach taken to planning and installing the completions. The paper also describes the use of a novel technique for perforating the platform wells with wireline guns.

High Resolution Sequence Stratigraphy and Reservoir Architecture of Proximal Alluvial Deposits: The Buntsandstein Facies of Central Spain: ABSTRACT

The Buntsandstein facies outcrops along a 12 km long, 150 m thick cuesta near Ayllon (Central Spain). The outcrop study is based on vertical sedimentological sections and continuous photo paneling, and demonstrates the presence of two depositional systems: an alluvial fan system in the lower half of the outcrop, and a straight and braided river system in the upper part of the outcrop. This overall evolution is probably related to base-level fall to base-level rise cycle, in which the reservoir architecture is linked to genetic units stacking pattern: during the base-level fall, the alluvial fan is prograding over sand flat and sandy alluvial plain deposits. Coarse and pebbly proximal sandsheets are interbedded with finer reddish distal deposits. Reservoirs units are laterally continuous, but silty alluvial plain deposits constitute vertical permeability barriers, during base-level stillstand, erosive channels and sandsheets are vertically amalgamated. Reservoirs units are laterally continuous and vertically connected, during the base-level rise, alluvial fan deposits are overlapped by straight river deposits. Reservoirs units are laterally connected but silty argillaceous alluvial plain horizons are preserved, at the end of the base-level rise, braided and straight river deposits are amalgamated. Fully connected, these reservoirs units have a very large lateral extension.more » A lithofacies database is compiled on this outcrop, and variograms, horizontal and vertical proportion curves are completed. Each stage of the base-level cycle is then quantitatively characterized by a specific heterogeneity pattern. The outcrop study will improve the prediction of reservoir extension and architecture in subsurface gas storage of the Paris basin.« less

Horizontal wells: still appealing in formations with discontinuous vertical permeability barriers? : Lien, S C; Haldorsen, H H; Manner, M J Pet TechnolV44, N12, Dec 1992, P1364–1370

Horizontal wells: still appealing in formations with discontinuous vertical permeability barriers? : Lien, S C; Haldorsen, H H; Manner, M J Pet TechnolV44, N12, Dec 1992, P1364–1370

Horizontal Wells: Still Appealing in Formations With Discontinuous Vertical Permeability Barriers?

Summary The appeal of horizontal wells often relies on increased productivitycompared to conventional vertical wells. A major productivity compared toconventional vertical wells. A major uncertainty is whether this productivityincrease is as great in formations containing discontinuous shales. With anumerical model study and a stochastic shale-modeling approach, the influenceof discontinuous shales on performance of vertical and horizontal wells wasstudied. We concluded that discontinuous shales cause a decrease in the Piratio between horizontal and vertical wells (compared with wells withoutshales) and that simulation studies are necessary to predict this decrease withan acceptable degree of accuracy. In a two-phase (oil/water) situation, weobserved that discontinuous shales increase oil recovery by decreasing watercut in both horizontal and vertical wells (compared -with wells withoutshales). Because of the large variability in the two-phase system results, long-term production testing may be the only means to obtain reliablepredevelopment data on the influence of discontinuous shales, Introduction The costs of a horizontal well rapidly approach the costs of a verticalwell; a horizontal well now typically costs only 1.2 to 1.5 times more per footdrilled. Thus, the expected and demonstrated productivity and coning benefitsof a horizontal well make it an increasingly attractive alternative toconventional vertical wells. Most North Sea sandstone reservoirs containsignificant vertical permeability barriers, such as shales. The shales affectthe reservoir transport properties because they may act as local no-flowbarriers within sand units or may subdivide the sands into separatehydrodynamic units. It is interesting, therefore, to investigate how thepresence of discontinuous permeability barriers will affect the appeal ofpresence of discontinuous permeability barriers will affect the appeal ofhorizontal wells compared with that of vertical wells, in terms ofproductivity. productivity. Analytical studies of horizontal-well productivityshow that the ratio of horizontal- to vertical-well productivity, J /J, decreases with decreases in the anisotropy ratio, k /k . From Fig. 1, it isapparent that the anisotropy ratio is of primary importance in screening theattractiveness of a horizontal well. Depending on the magnitude of thisparameter, a horizontal well may provide substantially increased productivitycompared with a provide substantially increased productivity compared with avertical well, or it may provide little or no increase in productivity, productivity, Where discontinuous vertical permeability barriers are presentit; the reservoir, two conceptually different strategies present it; thereservoir, two conceptually different strategies exist for estimation of theanisotropy ratio.Use of core plug measurements of k /k . This approachassumes that the influence of barriers on horizontal-well productivity isinsignificant. productivity is insignificant.Use of large-scale averagingfor the anisotropy ratio k /k. This approach assumes that the barriersinfluence the horizontal-well productivity by reduction of effective verticalpermeability. The shales are assumed to be zero-thickness sheets permeability. The shales are assumed to be zero-thickness sheets that do not affect k. Notethat if a well has been drilled and tested, a large-scale (k /k), may beavailable directly from the test interpretation. In Fig. 1, where we assumethat k/k = 1 from core measurements, we see that Strategies I and 2 willpredict either excellent or poor horizontal-well productivity benefit. Thispaper investigates poor horizontal-well productivity benefit. This paperinvestigates which of the two strategies to use to screen horizontal wells or, alternatively, whether either strategy is valid. The effect of discontinuousshales on water-coning behavior also has been investigated. The shales areexpected to disturb the water-cone advancement toward a horizontal well. Ifthis action reduces total water production, it would reduce the need forwater-treatment capacity on platforms. This, again, will be important toconsider when field development solutions are evaluated. Approach The study was restricted to investigation of two different reservoirsituations: a singlephase oil reservoir and a two-phase oil/water reservoirwith a bottomwater drive. In the single-phase situation, both analyticalmethods and numerical simulations were used to estimate productivity ratiosbetween horizontal and vertical wells. In the twophase situation, the study wasrestricted to numerical simulations. There are basically two different ways torepresent discontinuous vertical permeability barriers in a simulation model:explicit inclusion of transmissibility modifiers at the interface betweengridblocks in the simulation grid and implicit representation of the barriersthrough reduced effective vertical permeability, k . These methods werecompared in this study. permeability, k . These methods were compared in thisstudy. The explicit method gave the "correct" results. A single set ofshale (statistical) data was assumed and used throughout the study. In thesingle-phase case, three different horizontal-well lengths were considered:100, 250, and 500 m [328, 820, and 1,640 ft]. In the two-phase case, only thetwo longest horizontal wells (250 and 500 m [820 and 1,640 ft]) wereconsidered. For all stochastic shale realizations, the mean shale length rangedfrom 100 to 150 m [328 to 492 ft], depending on the shale density for thespecific realization. This limited the variety of shale-length vs. well-length, L /L cases studied.

Reservoir Simulation of Horizontal Wells in the Helder Field

Summary. Results of a reservoir simulation study of horizontal wells in a field that is entirely underlain by water and has a highly unfavorable mobility ratio are compared with about 4 years of actual field data. Finely gridded single-well models were used to investigate the short-term performance of the horizontal wells and to generate pseudofunctions for performance of the horizontal wells and to generate pseudofunctions for use in the field model. Introduction The Helder oil field, on the Dutch Continental Shelf, was brought on production 1982 and developed with 13 conventional wells. To improve oil recovery and to minimize water coning, the field was redeveloped during 1987 and 1988 with the drilling of 10 horizontal wells by sidetracking from existing wells. The simulation study described here was initiated to answer the following questions posed as a result of observing the performance posed as a result of observing the performance of the horizontal wells.Is the water-cut performance adversely affected by producing the wells at high gross rates?What effects do various well and reservoir parameters have on short-and long-term well parameters have on short-and long-term well behavior? Parameters to be considered are horizontal-well length, height above the water/oil contact (WOC) reservoir heterogeneity, localized vertical permeability barriers, and drainage area shape.Is water production distributed evenly along the horizontal wellbore, or does it enter preferentially at one or more intervals?Can production performance be improved by water shutoff treatments on existing wells or by modified completion design in future wells?Can the ultimate recovery be improved with additional infill horizontal wells? Field Description. The Helder field is an Block Q/1 of the Dutch North Sea, about 62 miles northwest of Amsterdam in 85 ft of water. The structure is a slightly faulted anticline at a depth of 4,600 ft. Formation dip along the northwest/southwest axis of the field is generally less than 1 degree. The field is underlain by water over its entire 1,140 acres of closure and has a maximum oil column of 131 ft. The reservoir is supported by a strong aquifer. Two other fields, Helm and Hoorn, brought on production at the same time as Helder, share the same aquifer. The original oil in place us estimated to be 72 × 10(6) STB. Oil gravity is 22 degrees API, and initial viscosity at reservoir conditions is 30 cp. Production is from the Vlieland sand, which has permeabilities ranging from 500 to 6,000 md. Production History With Conventional Wells. Production History With Conventional Wells. Helder was put on production in Oct. 1982. During 1982–84, the field was developed with 12 conventional (vertical/deviated) wells from a centrally located platform. In 1986, a previously drilled appraisal well (Well B1) was tied back to the platform by use of satellite tripod tower. Early water breakthrough and rapidly increasing water cut were expected in the conventional wells because of the unfavorable mobility ratio (M=25), flat field structure, and high vertical permeability. The majority of the wells produced water within a few days of production startup. This performance was predicted by initial computer simulations of single-well models, which showed that the critical rate to prevent water production had to be exceeded if the field was to be produced economically. produced economically. Subsequent simulations and preliminary history matching predicted that water-cut performance was not rate-sensitive for practical performance was not rate-sensitive for practical purposes. This led to the conclusion that purposes. This led to the conclusion that maximizing gross fluid off-take was necessary to improve economics. Individual wells were produced at rates up to 12,000 BFPD with water cuts from 85 to 97%. Some of the implications of the high-gross-fluid/ high-water-cut production strategy were decline in reservoir pressure and increase in workover frequency with conversion to larger pumps. To overcome these extreme coning conditions, Unocal Netherlands investigated the feasibility of redevelopment with horizontal wells. Redevelopment With Horizontal Wells. The first horizontal well (Well A4RD) was put on production in Jan. 1987. After the success of this well, nine more wells were horizontally sidetracked. Figs 1 and 2 show the locations of the original wells and the horizontal sidetracks. Table 1 summarizes the horizontal-well parameters. The performance aspects of parameters. The performance aspects of the Helder horizontal wells were the subject of a previous paper. Model Rock and PVT Properties. Seven layers were used in the field model and 15 layers in the single-well models. JPT P. 906