Variations In Reservoir Quality Research Articles

Importance of vertical effective stress for reservoir quality in the Skagerrak Formation, Central Graben, North Sea

The complex fluvial sandstones of the Triassic Skagerrak Formation are the host reservoir for a number of high-pressure, high-temperature (HPHT) fields in the Central Graben, North Sea. All the reservoir sandstones in this study comprise of fine-grained to medium-grained sub-arkosic to arkosic sandstones that have experienced broadly similar burial and diagenetic histories to their present-day maximum burial depths. Despite similar diagenetic histories, the fluvial reservoirs show major variations in reservoir quality and preserved porosity. Reservoir quality varies from excellent with anomalously high porosities of up to 35% at burial depth of >3500 m below seafloor to non-economic with porosities <10% at burial depth of 4300 m below seafloor.This study has combined detailed petrographic analyses, core analysis and pressure history modelling to assess the impact of differing vertical effective stresses (VES) and high pore fluid pressures (up to 80 MPa) on reservoir quality. It has been recognised that fluvial channel sandstones of the Skagerrak Formation in the UK sector have experienced significantly less mechanical compaction than their equivalents in the Norwegian sector. This difference in mechanical compaction has had a significant impact upon reservoir quality, even though the presence of chlorite grain coatings inhibited macroquartz cement overgrowths across all Skagerrak Formation reservoirs. The onset of overpressure started once the overlying Chalk seal was buried deeply enough to form a permeability barrier to fluid escape. It is the cumulative effect of varying amounts of overpressure and its effect on the VES history that is key to determining the reservoir quality of these channelised sandstone units. The results are consistent with a model where vertical effective stress affects both the compaction state and subsequent quartz cementation of the reservoirs.

Petrophysical Evaluation and the Effect of Shale Layers on Net Pay Zone Thickness in the Marun Oil Field, Iran

The Marun oil field is situated on the eastern part of Zagros, Iran. Aghajari Formation is cropping out on the surface. The Asmari formation, the Bangestan and Khami Groups are the Main reservoirs in this field and Asmari formation is the most important reservoir. Dolomitic carbonates are dominant lithology in the study well. Increasing of shale Layers in different layers caused to decrease of brittle property and this condition had investigated by petrophysical evaluation. According to this research, near to 29 percent shale has mixed with sandstone rock units in the study well which is comparable with maximum porosity there. Because, sandstone layers have shown the best porosity (near to 26 percent) in the study well. Also, good rocks based on water saturation and porosity are situated in sandstone units and poor rocks have existed in the limestone-dolomites. Therefore, facies changes in the Asmari formation can explain the observed variations in reservoir quality in the study area.

CONTROLS ON RESERVOIR DIAGENESIS IN THE LOWER GORU SANDSTONE FORMATION, LOWER INDUS BASIN, PAKISTAN

Sandstones in the Lower Cretaceous Lower Goru Formation in the Lower Indus Basin, Pakistan, are important reservoir rocks for oil, gas and gas‐condensates. For this study, nine metres of core from depths of more than 3400m from well X‐1 in the north‐central part of the basin were analysed for major variations in porosity and permeability in two Lower Goru sandstone units referred to as the Basal and Massive Sands. The Lower Goru Basal Sand was deposited in lower shoreface to inner shelf settings at the well location, while the Massive Sand was deposited in a middle to lower shoreface setting. In both units, intervals with moderate to good (&gt; 15%) porosities alternate with intervals with very low porosity (&lt;5%), and similar variations in core permeability were observed. In this paper, the reasons for this reservoir quality variation at well X‐1 are investigated. Specifically, the study addresses the influence of different clay types on reservoir porosity and permeability within the Lower Goru sands and the distribution and impact of hard cements such as calcite and quartz. A range of petrographical data is integrated including thin sections, whole rock and clay XRD results and SEM images, which together provide some insights into the causes of reservoir quality variation and into the paragenetic relationships between the authigenic minerals.Chlorite grain coats are present in the higher‐porosity sandstones and are interpreted to have inhibited the formation of quartz overgrowths. Dissolution of feldspar and volcanic rock fragments in both the Basal and Massive Sands has contributed to an increase in overall porosity at well X‐1. Relatively low porosity intervals in the Massive Sand are associated with the absence of chlorite grain coats and the presence of abundant quartz overgrowths. By contrast, low porosity intervals in the Basal Sand have undergone early poikilotopic calcite cementation.The formation of authigenic illite resulted in a significant decrease in permeability in both the Basal and Massive Sands. Chlorite and kaolinite also reduced the permeability. The chlorite originated mainly from the dissolution of volcanic rock fragments or from precursor depositional berthierine clay. The transformation of K‐feldspar to illite is suggested to be the main reaction responsible for the formation of both authigenic illite and quartz overgrowths in the two reservoir units; the observed pressure solution will also have contributed to development of quartz overgrowths.

Geological reservoir characterization of the Lower Cretaceous Dariyan Formation (Shu'aiba equivalent) in the Persian Gulf, southern Iran

The Aptian carbonate reservoirs of Persian Gulf, known as the Dariyan Formation (Shu'aiba equivalent), are among the most important oil reservoirs of Iran. Despite its significance, a little is known about the facies characteristics, diagenetic history, sequence stratigraphy, and reservoir quality of this formation. Using the new core data, this study presents an integrated geological reservoir characterization of this formation in four giant fields in the Persian Gulf. Using the results of the facies analysis it could be suggested that this unit formed in a shallow carbonate platform surrounding intra-shelf basins of Kazhdumi and Bab in the western and eastern Persian Gulf, respectively. A major relative sea-level fall in the Late Aptian resulted in exposure of this unit and subsequent clastic influx as well as meteoric diagenesis. This phase of meteoric diagenesis has resulted in some important diagenetic features, special geochemical trends, and considerable variations in reservoir quality of the Dariyan Formation. Sequence stratigraphic interpretation of this formation has resulted in the recognition of 2nd and 3rd order depositional sequences in the studied wells. They are closely correlated across the studied wells in the Persian Gulf, SW Iran, and other places in the Arabian Plate. Reservoir characterization has revealed that the high quality units are positioned at two stratigraphic intervals in the concerned reservoir. The first reservoir zone is located beneath the unconformity surfaces, where meteoric dissolution of grain-to mud-dominated facies has resulted in considerable amounts (10–40%) of vuggy, moldic, and micro-porosity in the highstand systems tracts (HSTs). The second reservoir zone of this formation has formed within the Lithocodium-algal facies, floatstone and boundstone, of inner ramp setting. The latter reservoir facies are mainly concentrated within the fields of the eastern Persian Gulf.

Reservoir quality variations within a sinuous deep water channel system in the Niger Delta Basin, offshore West Africa

Submarine fan channel reservoirs exhibit strong heterogeneity not only on channel architecture but also on the qualities of reservoirs, which can exert direct control over the fluid flow and remaining oil distribution during oilfield development. However, the distribution of the variations in the reservoir quality within submarine fan channel systems is poorly understood. This paper, which takes the submarine fan channel reservoirs of the X oilfield in the Niger Delta Basin as an example, aims to study the variations in reservoir qualities and the controlling mechanisms within a sinuous deep-water channel system. The studies are based on the integration of core analysis, well-logging interpretation, seismic inversion and interpretation constrained by channel architecture.The results show that variations in the reservoir quality within a sinuous deep-water channel system are primarily controlled by rock texture, lithofacies (association) and channel architecture under the circumstance of weak diagenesis. (1) The grain sorting and clay content mainly control the reservoir's porosity and permeability, respectively, while the relationship between grain size and the reservoir's properties is complicated because of the strong heterogeneity in the rock textures for different lithofacies. Cross-laminated fine sandstones have the highest porosity because of their good sorting, while massive medium to coarse sandstones have the highest permeability because of their low clay content. (2) Channel fillings are divided into four types (Type I – Type IV), which bear different reservoir qualities according to the lithofacies associations. Within a complete channel system, the channel fill types evolve progressively upward as the dominant gravity flow types evolve, which leads to the vertical differential distribution of porosity and permeability. (3) The relatively high porosity-permeability zones in the plane of a channel belt exhibit two patterns: multiple lenticular strips and single lenticular strips, which are controlled by the channel's architecture.

Characteristics of axially-sourced turbidite sedimentation on an active wedge-top basin (Annot Sandstone, SE France)

In order to develop viable depositional models for wedgetop basins, the control exerted by active structural relief on turbidite depositional patterns should be well understood at different scales (from limb slope to interconnected synclinal troughs). This is particularly the case for systems with axial sediment supply, for which little data are available. This paper presents a detailed field study of two depocentres in the Upper Eocene – Lower Oligocene Annot Sandstone of the alpine foreland basin of SE France, which was fed axially from the Corsica–Sardinia Massif to the south. The depocentres are partially preserved in a series of outliers. The Annot outlier preserves turbidites deposited on the gently dipping limb of an asymmetrical syn-depositional syncline, while, to the north, the NE Grand Coyer outlier preserves highly confined turbidites deposited on a steep and complex synclinal limb. Structural, stratigraphic and sedimentological data demonstrate that these turbidite depocentres were controlled by active folding and faulting, including oblique structures. Structural controls were more complex on the steep eastern synclinal limbs than on shallowly dipping western limbs. Integration of palaeocurrent data allow feeder pathways and their evolving interconnections to be traced between successive downstream depocentres in space and time. A 3D depositional model for axially supplied active wedgetop depocentres is proposed and compared to transversely fed wedgetop systems, particularly in terms of facies distributions and variations in reservoir quality. Axially supplied systems are marked by a higher lateral confinement and, as a consequence, are more sensitive to relief created by oblique structures. As a result facies distributions are more strongly controlled by (active or inactive) substratum relief than by intrinsic flow properties, leading to a higher potential for stratigraphic traps.

Simulating flow through forward sediment model stratigraphies: insights into climatic control of reservoir quality in isolated carbonate platforms

Whilst sophisticated multiphase fluid flow models are routinely employed to understand behaviour of oil and gas reservoirs, high-resolution data describing the three-dimensional (3D) distribution of rock characteristics is rarely available to populate models. We present a new approach to developing a quantitative understanding of the effect of individual controls on the distribution of petrophysical properties and their impact on fluid flow. This involves simulating flow through high-detail permeability architectures generated by forward modelling of the coupled depositional–diagenetic evolution of isolated platforms using CARB3D + . This workflow is exemplified by an investigation of interactions between subsidence and climate, and their expression in spatial variations in reservoir quality in an isolated carbonate platform of similar size and subsidence history to the Triassic Latemar Platform. Dissolutional lowering during subaerial exposure controls platform-top graininess via platform top hydrodynamics during the subsequent transgression. Dissolved carbonate is reprecipitated as cements by percolating meteoric waters. However, associated subsurface meteoric dissolution generates significant secondary porosity under a more humid climate. Slower subsidence enhances diagenetic overprinting during repeated exposure events. Single-phase streamline simulations show how early diagenesis develops more permeable fairways within the finer-grained condensed units that can act as thief zones for flow from the grainier but less diagenetically altered cyclic units.

Shaly sand rock physics analysis and seismic inversion implication

The analysis of well data from the Enfield field of the Exmouth Sub-basin, WA, indicates that both cementation and pore-filling clay appear to have a stiffening effect on the reservoir sands. The elastic contrast between brine sand and the overlying shale is often small and the large amplitudes observed from seismic data are associated with hydrocarbon content. More detailed rock physics and depth trend analysis of elastic and petrophysical properties, however, indicate significant spatial variability in the cap rock shales across the field with different sand shale mixtures, causing changes in the elastic response of the rock. Areas where shales are softer produce weak seismic amplitude contrasts even with high hydrocarbon saturation; the amplitude response being similar to areas with stiffer shales and brine-filled sands. The variations in reservoir quality are, therefore, masked by the distribution of the brine, oil and gas, as well as the variations in the cap rock. The Enfield rock physics analysis provides an example of reducing amplitude ambiguity over lithology-fluid variation and improves the chance of successful interpretation of the results of seismic inversion.

Carbonate porosity creation by mesogenetic dissolution: Reality or illusion?: Discussion

In their recent discussion of the recognition of late burial dissolution of carbonates, Ehrenberg et al. (2012) use our article (Beavington-Penney et al., 2008) as an example of a study that mistakes late burial (mesogenetic) porosity for pores that formed much earlier in the diagenetic sequence. Commenting on our study of reservoir quality variation in Eocene nummulitic limestones, Ehrenberg et al. (2012, p. 229) note that …

Defining net reservoir using the dual packer wireline formation tester: a case study from the Clio, Acme, and Acme West fields

The Clio, Acme, and Acme West gas fields lie in the WA-42-R permit in the Carnarvon Basin, offshore WA. The reservoirs at the Clio, Acme, and Acme West fields generally have excellent reservoir characteristics with multi-Darcy permeabilities. Some additional potential may occur in more marginal-quality reservoirs. To determine the potential of the marginal sands, a dual packer wireline formation tester (WFT) was used to constrain petrophysical cut-offs of the target Mungaroo and Brigadier formations, which consist of fluvial and deltaic reservoirs. A decision-based approach in the application of the dual packer WFT has allowed for systematic evaluation of the dynamic behavior of each depositional environment at proposed reservoir cut-offs, and has provided insight into the flow mechanisms controlling productivity in the near-well environment The controls on reservoir quality between these two depositional environments are very different. The fluvial reservoirs are characterised by large ranges of permeability variation for very small changes in porosity as a function of grain-size variation. The dual packer WFT stations conducted in the Clio–3 fluvial sands demonstrate the role of entry pressure to gas charge, and allowed for the quantification of the minimum total porosity needed for net reservoir to be present in the well The sands in the sand/shale laminae of the deltaic environment have much less reservoir quality variation than the sands in the fluvial system. Reservoir quality is controlled by the connectivity of these sands both laterally and vertically. Sand connectivity is inferred from neutron density crossover, and is tested with dual packer WFT stations at Acme West–2 The integration of data gathered at the Clio–3 and Acme West–2 dual packer WFT stations has been used to establish net-to-gross cut-offs applied to these reservoirs

Impact of regional variation in detrital mineral composition on reservoir quality in deep to ultradeep lower Miocene sandstones, western Gulf of Mexico

Future exploration in lower Miocene sandstones in the Gulf of Mexico will focus increasingly at depths greater than 4.5 km, and reservoir quality will be a critical risk factor in these deep to ultradeep reservoirs. The goal of this study was to understand the variation in reservoir quality of lower Miocene sandstones across the western Gulf of Mexico. To do this, we examined regional variation in detrital mineral composition, diagenesis, and reservoir quality in five areas: (1) Louisiana, (2) upper Texas coast, (3) lower Texas coast, (4) Burgos Basin, Mexico, and (5) Veracruz Basin, Mexico using petrographic and petrophysical data from depths of 0.9–7.2 km.There are strong variations in mineralogical composition within the study area. Lower Miocene sandstones from offshore Louisiana have an average composition of quartz = 86%, feldspar = 12%, and rock fragments = 2% (Q86F12R2). Feldspar and rock-fragment content increase southward as source areas shifted to include volcanic and carbonate rocks. Composition of samples from offshore Texas ranges from Q67F24R9 in the upper Texas coast to Q58F24R19 in the lower Texas coast. Lower Miocene sandstones from the onshore Burgos Basin, northern Mexico, have an average composition of Q54F22R23, whereas sandstones from the Veracruz Basin, southern Mexico, contain the highest proportion of rock fragments, Q33F12R55. Main diagenetic events in quartz-rich lower Miocene sandstones in Louisiana were mechanical compaction and precipitation of quartz cement. Compactional porosity loss increased to the south with increasing rock-fragment content. Calcite is the most abundant cement in the south and is strongly related to reservoir quality loss.At moderate burial depths, the best reservoir quality occurs in quartz-rich sandstones in Louisiana and decreases with increasing lithic content in Texas and Mexico. Porosity is higher in Louisiana and upper Texas than in lower Texas and Mexico at all depths and temperatures, but at depths >5 km and temperatures >175 °C, porosity differences are lessened. The lower Miocene sandstone trend in the western Gulf of Mexico from Louisiana to Mexico is an example of the importance of variation in detrital mineralogy as a control on diagenesis and reservoir quality.

Salt-induced stress anomalies: an explanation for variations in seismic velocity and reservoir quality

ABSTRACT Accurate rock property prediction is often a critical success factor for wells targeting hydrocarbons. This applies not only to reservoir porosity and permeability affecting productivity directly, but also to acoustic velocity, seismic time-to-depth conversion and depth prognosis. A detailed analysis of variation in the overburden rock velocity in the Southern North Sea has shown that Triassic velocity variations of up to 18% occur within short distances (e.g.

Diagenetic controls on reservoir quality in Middle to Upper Jurassic sandstones in the South Viking Graben, North Sea

The deeply buried synrift play of the South Viking Graben is characterized by highly variable reservoir quality. An integrated approach incorporating petrophysics, petrography, and one-dimensional basin modeling methods was applied to investigate these variations. Analysis shows that average porosities below 4000 m (13,123 ft) (vertical depth below sea floor) range from approximately 5% to as much as about 25% in comparable quartz arenitic sandstones. From porosity-depth trends, three porosity categories can be recognized (normal-, low-, and high-porosity sandstones). Normal-porosity sandstones fall along the regional average porosity-depth trend. Low-porosity sandstones have been subject to extensive quartz cementation as a consequence of a higher degree of thermal maturity and plot below the regional porosity-depth trend. High-porosity sandstones plot above the regional porosity-depth trend. Here, quartz cementation has been inhibited by grain-coating microquartz, and thus porosity has been preserved. Hydrocarbon emplacement has previously been thought to have inhibited quartz cementation in the study area, but this study concludes that the reservoirs are mainly water-wet, allowing for continued quartz cementation despite the presence of hydrocarbon pore fluids. Predicting the distribution of microquartz-coated sandstones and the degree of thermal maturity is therefore fundamental for successful exploration in the deeply buried parts of the synrift play. This study presents a regional and stratigraphic framework for such predictions that may be incorporated into play models in the area.

Eagle Ford shale prospecting with 3D seismic data within a tectonic and depositional system framework

The south Texas Eagle Ford shale formation in is an important emerging shale play in the United States. More than 1510 wells have either been drilled or permitted in the play. What has emerged is a well-defined downdip gas play that transitions rapidly updip into less well-defined wet gas and oil fairways. With initial gas well rates exceeding 17 million cubic feet per day and initial oil well rates in excess of 1000 barrels of oil per day common in the expanding play, exploration companies are pursuing methods to optimize drilling plans. Limited well and core data describing the Eagle Ford require the use of 3D seismic to help characterize reservoir quality variations, avoid drilling hazards, and help predict sweet spots. Modern, long-offset, full-azimuth 3D is an essential tool for building a geophysical description of the shale between wells. Anisotropic time imaging, feeding both acoustic and elastic inversions, is helping operators gain better insight into the reser-voir's variability. The following discussion highlights components of an ongoing effort to extract value from seismic data in shale prospecting. Unfortunately, limited well data for calibration, as in many immature shale plays, remains the primary constraint on confident linkage between the actual reservoir quality and seismic measurements.

Insight Into Integrated Reservoir Management Using a Top-Down Intelligent-Reservoir-Modeling Technique: Application to a Giant and Complex Oil Field

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 132621, ’New Insight Into Integrated Reservoir Management Using a Top- Down, Intelligent-Reservoir-Modeling Technique: Application to a Giant and Complex Oil Field in the Middle East,’ by Amirmasoud Kalantari- Dahaghi, Shahab D. Mohaghegh, and Yasaman Khazaeni, SPE, West Virginia University, prepared for the 2010 SPE Western Regional Meeting, Anaheim, California, 27-29 May. The paper has not been peer reviewed. Top-down intelligent reservoir modeling (TDIRM) integrates reservoir-engineering analytical techniques with artificial intelligence and data mining to arrive at an empirical, cohesive, and spatiotemporally calibrated full-field model. The model is used to predict reservoir performance to recommend field-development strategies. Introduction TDIRM attempts to provide insight into fluid flow in the reservoir by starting with field measurements such as well-production history and well logs. Other data such as core analysis, well tests, and seismic can be used to increase model accuracy. Although not intended as a substitute for conventional reservoir simulation of large complex fields, this approach to reservoir modeling and management can be used as an alternative to traditional reservoir simulation and modeling for cases in which performing conventional modeling is cost and manpower prohibitive. If a conventional model already exists, TDIRM may complement the conventional technique with an independent assessment of the reservoir/well data to optimize development-strategy and recovery enhancement. In this study, TDIRM was performed on a giant complex oil field in the Middle East that has produced for a half-century. The reservoir has produced under natural depletion, with a strong waterdrive maintaining reservoir energy. The formation is a complex mix of clastics and carbonates of variable reservoir quality. This prolific reservoir has highly complex flow behavior. Methodology TDIRM uses accepted reservoir-engineering techniques such as decline-curve analysis, type-curve matching, (single-well) production-history matching, volumetric-reserves estimation, and calculation of recovery factors. These analyses are performed on individual wells. By use of statistical techniques, multiple production indicators [i.e., first 3-, 6-, and 9-month cumulative production and the 1-, 3-, 5-, and 10-year cumulative oil, gas, and water production and gas/oil ratio (GOR) and water cut] are calculated. To model the behavior of nondeclining-production characteristics such as GOR and water cut, intelligent decline-curve analysis is performed on GOR for which a negative decline is normal behavior. Intelligent decline-curve analysis is specific to TDIRM, and it is performed by use of an adaptive time-series-modeling technique that trains itself with existing data and predicts system behavior for a specific length of time into the future.

The sabkha sequence at Mussafah Channel (Abu Dhabi, United Arab Emirates): Facies stacking patterns, microbial-mediated dolomite and evaporite overprint

ABSTRACT The Mussafah Channel is a man-made canal cut perpendicular to the coastline, located to the southwest of the city of Abu Dhabi, United Arab Emirates, and is ideal for studying coastal depositional processes in an arid environment. The channel walls reveal a few meters of Pleistocene reworked dune deposits, unconformably overlain by Holocene carbonates and sabkha evaporites. The Holocene succession consists of intertidal to shallow subtidal sediments that vary significantly along depositional strike direction. Bladed gypsum crystals, gypsum rosettes, and nodular to highly contorted, discontinuous bands of classic sabkha anhydrite are present along the channel walls. Sedimentology, petrography, SEM, X-ray diffraction, and radiocarbon age-dating analyses of the sabkha sequence show the following profile from base to top: (1) non-bedded carbonate-rich sand: reworked aeolianite with an approximate (ca.) radiocarbon age in years (yrs) before present (BP) ca. 26,800 14C yrs BP; (2) cross-bedded to non-bedded carbonate-rich sand: aeolianite/reworked aeolianite (ca. 24,000–23,500 14C yrs BP); (3) crinkly-laminated stromatolitic bindstone: intertidal, low-energy microbial mat (ca. 6,600–6,200 14C yrs BP); (4) lower, discontinuous and in places reworked hardground: cemented channel-lag deposits (ca. 6,400 14C yrs BP); (5) peloid-skeletal packstone with rootlets or microbial-laminated peloid-skeletal packstone, laterally grading into fine- to coarse-grained, cross-bedded, cerithid-rich, bioclastic packstone, grainstone, and rudstone: lowermost intertidal to shallow subtidal, low-energy, mud-rich rooted and microbial-laminated lagoonal deposits and moderate- to high-energy, intertidal to shallow subtidal tidal-channel, tidal-delta, and tidal-bar deposits (ca. 6,200–5,200 14C yrs BP); (6) upper discontinuous and shingled hardground: cemented beach rock (ca. 5,700 14C yrs BP); (7) cross-bedded, bioclastic rudstone/grainstone, grading laterally into intervals displaying bladed gypsum crystals and nodular to enterolithic anhydrite: intertidal to shallow subtidal, high-energy longshore beach bar and beach spit deposits; overprinted by sabkha gypsum and anhydrite (ca. 5,000 14C yrs BP). Significant amounts of dolomite were found within the rooted and microbial-laminated mud-rich lagoonal carbonates, some of the tidal-channel/lagoonal deposits, the buried crinkly-laminated microbial mats, and within some of the Pleistocene carbonate-rich sands. The dolomite is very fine-crystalline and displays spherical morphologies as well as subhedral to euhedral dolomite rhombohedra. The formation of dolomite is interpreted to be related to dolomite-mediating microbial organisms which form the widespread microbial mat along the Abu Dhabi coastline. Microbial organisms are also present within the rooted and microbial-laminated lagoonal carbonates and, most probably, within all the other studied carbonates and the Pleistocene carbonate-rich sands. Biopolymers of microbial origin, referred to as Extracellular Polymeric Substances (EPS), are interpreted to play a key role in primary dolomite formation. The sabkha sequence at Mussafah Channel formed during the post-glacial Flandrian transgression, resulting in the reworking of the Pleistocene aeolian dunes and the deposition of intertidal to shallow subtidal carbonates. Recent find of whale bones within tidal-channel deposits overlying the microbial mat further document the initial Holocene transgression. During a subsequent slight sea-level fall (regression), these carbonates were overprinted by gypsum and anhydrite. The observed lateral and vertical facies variations reflect primary reservoir quality variations, an important aspect to be considered for geological facies and reservoir quality modeling.

Successful Implementation of Horizontal Openhole Gravel Packing in the Stybarrow Field, Offshore Western Australia

Summary Key sandface completion challenges were faced in the selection, design, planning, and execution phases of the openhole horizontal gravel-pack completions in the deepwater Stybarrow field, offshore Western Australia. Only limited technical experience and infrastructure were available in the country to support such a complex operation. Additionally, the lateral reservoir-quality variations and challenging sand/shale heterogeneities have necessitated an early focus on appropriate reservoir-drilling-fluid (RDF) design, detailed sand-screen selection, and gravel-pack modeling to minimize premature screenout during gravel packing and to ensure minimal formation damage. This paper documents the multidisciplinary approach that commenced during the field-appraisal and data-acquisition stages to derive the sand-management plan and that culminated in the successful implementation of four horizontal openhole gravel packs. A novel RDF design, extensive formation-damage testing, and the selection of the circulating gravel-packing technique have led to the successful sand-control implementation, with pack factors in excess of 100%. Attention to detail during detailed design, extensive contingency planning, and diligent execution were major contributing factors in delivering high-quality wells capable of producing as per basis of well design, proved by early production performance. The Stybarrow development represents the first successful implementation of horizontal openhole gravel packing in Australia.

Multiple-scale facies and reservoir quality variations within a dolomite body – Outcrop analog study from the Middle Triassic, SW German Basin

This study focuses on a porous dolomite body in the proximal part of an epeiric carbonate ramp (Triassic Muschelkalk, South German Basin), analogous to hydrocarbon-bearing dolomite reservoirs in the Middle East (e.g. Khuff and Arab Formations). The dolomite body is made up of shoal, lagoonal and peritidal facies types and is built by a three-fold hierarchy of cycles (3rd-order to 5th-order). The best reservoir quality occurs in finely crystalline lagoonal dolo-mudstones (mean: K = 37.8 mD; φ = 20.2%) with micro-intercrystalline and vuggy porosity. Coarsely crystalline, shoal-related dolo-grainstones show variable reservoir potential (mean: K = 30.1 mD; φ = 4.4%) due to late diagenetic modification. Reservoir quality significantly decreases in the non-dolomitized foreshoal section (mean: K = 4.5 mD; φ = 3.6%). Stratigraphically, the most porous dolomite occurs in the upper regressive portion of the 3rd-order cycle. Reservoir quality progressively decreases towards the limy bottom of the section. Outcrop mapping showed high lateral continuity for the distribution of facies types and poroperm values on the scale of several 10s of meters. Within correlated 5th-order cycles, considerable facies and poroperm heterogeneity is already observed on the 100s of meters-scale. On a 1000s of meters-scale, the facies and lithology distribution is controlled by the geometry of a gently inclined carbonate ramp. During regression, a progradational pattern is recognized, marked by a basinward migration of backshoal facies and a down-dip decrease of dolomite body thickness. Lithology, facies and poroperm data from outcrops and cores were used for 3D-modeling with the software Petrel. The modeled variations in the poroperm distribution are consistent with the degree of heterogeneity expected for a combination of laterally persistent lithology and highly variable facies. Results of this study may help to better understand the reservoir heterogeneity of inner ramp dolomite bodies and can be applied to improve characterization and modeling of similar dolomite reservoirs.

Geological sequestration of carbon dioxide in the Cambrian Mount Simon Sandstone: Regional storage capacity, site characterization, and large-scale injection feasibility, Michigan Basin

The Mount Simon Sandstone (Cambrian) is recognized as an important deep saline reservoir with potential to serve as a target for geological sequestration in the Midwest, United States. The Mount Simon Sandstone in Michigan consists primarily of sandy clastics and grades upward into the more argillaceous Eau Claire Formation, which serves as a regional confining zone. The Mount Simon Sandstone lies at depths from about 914 m (3000 ft) to more than 4572 m (15,000 ft) in the Michigan Basin and ranges in thickness from more than 396 m (1300 ft) to near zero adjacent to basement highs. The Mount Simon Sandstone has variable reservoir quality characteristics dependent on sedimentary facies variations and depth-related diagenesis. On the basis of well-log-derived net porosity from wells in the Michigan Basin, estimates of total geological sequestration capacity were determined to be in excess of 29 billion metric tons (Gt). Most of this capacity is located in the southwestern part of the state. Numerical simulations of carbon dioxide (CO2) injection were conducted using the subsurface transport over multiple phases-water-CO2-salt (STOMP-WCS) simulator code to assess the potential for geologic sequestration into the Mount Simon saline reservoir in the area of Holland, Ottawa County, Michigan. At this locality, the reservoir is more than 260 m (850 ft) thick and has a minimum of 30 m (100 ft) of net porosity. The simulation used a CO2 injection period of 20 yr at a rate of 600,000 metric tons (t)/yr, followed by an equilibration period of 280 yr, for a total of 300 yr. After 20 yr, the total amount of CO2 injected is 12 million metric tons (Mt); after 300 yr, 9.8 Mt is modeled to remain as a free-phase (nonentrapped) supercritical CO2, 0.7 Mt is capillary-entrapped (residual) supercritical CO2, and 1.5 Mt dissolved into the brine. The injected CO2 spread to an area with a radius of 1.8 km (1.12 mi) after 20 yr of injection at a single well and to an area with a radius of 3.8 km (2.36 mi) after 300 yr. The low-permeability Eau Claire retards the upward migration of CO2. Pressures during injection at the bottom of the cap rock (1540.5-m [5054-ft] depth) are well below the fracture pressure limit of 27.9 MPa (4046.6 psi), assuming a fracture pressure gradient of 0.018 MPa/m (0.8 psi/ft) caused by the high permeability of the Mount Simon Sandstone.

Kuwait Case Study: Integrated-Reservoir-Management Approach Offsets Effects of Reservoir Heterogeneity, Injectivity Challenges, and Delayed Waterflood

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 111472, "Integrated- Reservoir-Management Approach Beats the Impact of Reservoir Heterogeneity, Injectivity Challenges, and Delayed Waterflood in Upper Burgan Reservoir in North Kuwait - A Case History" by H.B. Chetri, SPE, Abd Aziz El-Sabry, Mishal Al-Mufarej, and Ealian Al-Anzi, SPE, Kuwait Oil Company, prepared for the 2008 SPE North Africa Technical Conference and Exhibition, Marrakech, Morocco, 12-14 March. The paper has not been peer reviewed. The Upper Burgan is a multilayered reservoir in the Sabiriyah field of northern Kuwait, currently undergoing the initial phase of waterflood development. The reservoir is highly complex with respect to reservoir heterogeneity, connectivity, and structural compartmentalization. Early waterflood performance was too poor to achieve the targeted injection rates. Detailed channel mapping enhanced the subsurface understanding to add value to the ongoing drilling, production, and injection plans. The integrated-reservoir-management (IRM) approach, with a strategy for depletion and pressure support for each segment, increased short-term production and is sustaining the rates. The current and short-term drilling plans target reservoir segments with higher pressures for well placement. Introduction The Upper Burgan reservoir in the Sabiriyah field was discovered in the 1950s. The reservoir comprises a complex series of tidal, estuary, deltaic, valley-fill, and shoreface sands interbedded with semicontinuous shales. The first facies is carbonaceous sand, fine- to medium-grained sand with porosity of 22 to 25% and permeability greater than 400 md. The thickness can reach 40 ft, with 10 to 20 ft being typical. The second sand-prone facies is bioturbated sand, a very-fine- to fine-grained facies with variable reservoir quality. The thickness averages 20 ft. The third facies is heterolithic sand and typically is very-fine- to fine-grained. This facies type is abundant in the Upper Burgan. Reservoir quality is erratic because of its laminated nature, and vertical permeability is low. The reservoir was subdivided into five mappable layers (UB1 through UB5) in 1992. This zonation scheme was reviewed and modified where appropriate by the Upper Burgan Team in 1997. Average net-pay thickness is 60 to 100 ft. The initial reservoir pressure was 3,800 psia, with a bubblepoint pressure of 1,500 to 2,450 psia. The current reservoir pressure ranges from 2,600 to 3,500 psia. Reservoir Heterogeneity Key lessons from analog reservoirs suggest the necessity of flexible development planning. Connectivity was reviewed in terms of stratigraphy, structure, and pressure, with the following general conclusions.In many analogous reservoirs, the paralic depositional environment proved more complex than originally thought. Closely spaced wells can exhibit drastic changes in sand character—continued infill drilling most likely will be necessary in some parts of the field in the future.Most peripheral floods in paralic environments are converted to pattern floods.Small faults in the Upper Burgan can cause nonjuxtaposition of productive layers.Structure, channel architecture, and stratigraphy likely will play a significant role in the waterflood performance of the reservoir.