Qishn Formation Research Articles

Sequence stratigraphic framework and distribution of potential reservoirs: Early Cretaceous Qishn Formation, Dhofar, Southern Oman

Sequence stratigraphic framework and distribution of potential reservoirs: Early Cretaceous Qishn Formation, Dhofar, Southern Oman

Обоснование границ формации Кишн на основе комплекса сейсмических данных

The paper considers the issues of applying 2D and 3D modeling methods to justify the boundariesof the Qishn formation based on a set of seismic data for the Tawila field (Republic of Yemen). The proposed algorithms and approaches to identifying reservoir boundaries and subsequent modeling of the Qishn formation reservoir make it possible to assess not only the structure of the oil-saturated part, but also to assess the possibility of detecting promising oil production zones for the territory of neighboring fields, as well as oil-bearing formations in the upper and lower formations.

Application of 3D Static Modelling in Reservoir Characterization: A Case Study from the Qishn Formation in Sharyoof Oil Field, Masila Basin, Yemen

AbstractThree‐dimensional (3D) static modelling techniques are applied to the characterization of the Qishn Formation (Fm.) in the Sharyoof oil field locating within the Masila basin, southeastern Yemen. The present study was initiated by the seismic structural interpretation, followed by building a 3D structural framework, in addition to analysing well log data and from these, 3D facies and petrophysical models are constructed. In the Sharyoof oil field, the Qishn Fm. exhibits depth values within the range of 400–780 m below sea level, with a general increase towards the SSE. A set of high dip angle normal faults with a general ENE–WSW trend dissect the rocks. The strata are also folded as a main anticline with an axis that is parallel to the fault trend, formed as a result of basement uplift. According to the facies models, the Qishn Fm. comprises 43.83% limestone, 21.53% shale, 21.26% sandstone, 13.21% siltstone and 0.17% dolomite. The Qishn Carbonates Member has low porosity values making it a potential seal for the underlying reservoirs whereas the Upper Qishn Clastics S1A and C have good reservoir quality and S1B has fair reservoir quality. The Upper Qishn Clastics S2 and S3 also have fair reservoir quality, while the Lower Qishn Clastics zone has good reservoir quality. The water saturation decreases towards the west and east and increases towards north and south. The total original oil in‐place (OOIP) of the Upper Qishn clastics is 106 million STB within the S1A, S1C and S2 zones. Drilling of development wells is recommended in the eastern study area, where good trapping configuration is exhibited in addition to the presence of a potential seal (Upper Qishn Carbonates Member) and reservoir (Qishn Clastics Member) with high porosity and low water saturation.

К вопросу повышения качества геологической модели формации Кишн месторождения Шариуф

In this paper, the issues of the geological structure of the Sharyoof oilfield are considered and special attention is paid22to the study of the S oil-bearing horizon, the results of complex petrophysical (laboratory), seismic and well log data22are presented. The S oil-bearing horizon belongs to the Qishn formation and was studied to assess the reservoirproperties of the Qishn sandstone, as well as to highlight the features of the location of hydrocarbons in the Sharyoof oilfield, the Sayun-Masila basin for building 3D models and detailing the boundaries of the location of different lithotypes of rocks (sandstones, sandy-silty and carbonate reservoir rocks). The reservoir rocks are dominatedby sandstones with good porosity and permeability, which are usually interbedded with silt-clayey interlayers. Well studies have shown that the Qishn sandstone is classified into subunits with different reservoir characteristics and hydrocarbon potential. A number of qualitative and quantitative analyzes and well logs were used to characterize the various divisions of the Qishn field and determine its hydrocarbon potential.

Echinoids from the upper Qishn Formation (lower Aptian) in the Haushi-Huqf area, Oman Interior Basin, Arabic Peninsula

The Haushi-Huqf region (central Oman) is a structural high on which the Qishn and Nahr Umr formations represent the upper Barremian–lower Aptian and Albian intervals, respectively, which record some of the transgressive events that covered large portions of the Arabian Peninsula during the mid-Cretaceous. With a complex post-depositional evolution through processes of burial, uplift, tilting and intense denudation, the current landscape allows a glimpse of a virtually exhumed ocean floor, as it would have occurred about 120 myr ago. A NW–SE hiking of about 1200 m in Wadi Bauw, in the southeasterly portion of Jabal Dumur, has allowed the uninterrupted monitoring of the transition of depositional palaeoenvironments from a restricted lagoon to an open-marine platform, below storm wave base. The echinoids Tetragramma deshayesi (Cotteau, 1864), Coenholectypus neocomensis (Gras, 1848) and Pliotoxaster cf. comanchei (Clark, in Clark and Twitchell, 1915) come from the upper part of the Qishn Formation and are dated as early Aptian, based on the presence of the foraminifer Voloshinoides murgensis Luperto Sinni and Masse, 1993 and the rudists Glossomyophorus costatus Masse, Skelton and Slišković, 1984, Offneria nicolinae (Mainelli, 1983) and O. murgensis Masse, 1992. All specimens were collected from marly facies in which orbitolinid foraminifera predominate, in what could have been the external portion of an open platform, immediately after the occurrence of carbonate shoals consisting of oncolitic/peloidal grainstones/packstones and rudists that occur in association with bioconstructions of the Lithocodium/Bacinella consortium. Morphological characteristics of the echinoids suggest that, although Tetragramma was epifaunal and Coenholectypus endofaunal, both would have inhabited shallow and protected environments, composed of coarse sandy sediments in an internal lagoon. In contrast, the genus Pliotoxaster would have been better adapted to deeper environments or to settings with lower oxygen levels, i.e., being more closely compatible with the environment it was found in. Thus, it is likely that representatives of Coenholectypus and Tetragramma had been transported from the lagoonal regions and/or near the carbonate shoals to deeper regions with fore-bank characteristics.

Petrophysical properties of Cretaceous clastic rocks (Qishn Formation) in the Sharyoof oilfield, onshore Masila Basin, Yemen

The subsurface of Qishn clastic rocks, which are exposed in the Sharyoof oilfield, has been studied. The petrophysical properties, i.e., porosity and permeability of Qishn clastic reservoir rocks were investigated using well logging coupled with core data. The results were used to evaluate the reservoir quality and hydrocarbon occurrence potential. The lithology of the Qishn clastic was computed from well logs, which indicate that the lithofacies of the Qishn clastic at Sharyoof oilfield is mainly composed of sandstone and carbonates with a low amount of shale intercalations.Generally, the Qishn clastic reservoir rocks have good reservoir quality with porosity values, averaging ∼19.0%. These porosity values are mainly intergranular primary and secondary porosity. Permeability is likewise variable with values in the range of 0.001–7270mD and an average of 413mD. This is conformed from core porosity and permeability results. However, the relatively high values of effective porosity and permeability are due to lower shale contents in the Qishn clastic rocks. The Qishn clastic reservoir rocks have been differentiated into net-pay and non-pay zones according to the cutoff (i.e., effective porosity ⩾10%, shale volume ⩽30% and water saturation ⩽50%). The Qishn clastic reservoir rocks have high hydrocarbon saturation exceeding 70%, with relatively high movable oil, indicating that the production is mainly oils. Therefore, the Early Cretaceous Qishn Formation acts as a hydrocarbon reservoir in the Sharyoof oilfield, Masila Basin, eastern Yemen.Reservoir property distributions of the Qishn clastic rocks such as net-pay thickness, porosity, permeability and hydrocarbon potential indicate that the best prospective region for oil accumulation is located in the central part of the study area. Therefore, the Qishn clastic rocks in the central part of the study area have promising reservoir characteristics and hydrocarbon occurrence potential, which should be taken into consideration during future development of the Sharyoof oilfield.

Petroleum source rock characterisation and hydrocarbon generation modeling of the Cretaceous sediments in the Jiza sub-basin, eastern Yemen

Cretaceous sedimentary rocks of the Mukalla, Harshiyat and Qishn formations from three wells in the Jiza sub-basin were studied to describe source rock characteristics, providing information on organic matter type, paleoenvironment of deposition and hydrocarbon generation potential. This study is based on organic geochemical and petrographic analyses performed on cuttings samples. The results were then incorporated into basin models in order to understand the burial and thermal histories and timing of hydrocarbon generation and expulsion.The bulk geochemical results show that the Cretaceous rocks are highly variable with respect to their genetic petroleum generation potential. The total organic carbon (TOC) contents and petroleum potential yield (S1 + S2) of the Cretaceous source rocks range from 0.43 to 6.11% and 0.58–31.14 mg HC/g rock, respectively indicating non-source to very good source rock potential. Hydrogen index values for the Early to Late Cretaceous Harshiyat and Qishn formations vary between 77 and 695 mg HC/g TOC, consistent with Type I/II, II-III and III kerogens, indicating oil and gas generation potential. In contrast, the Late Cretaceous Mukalla Formation is dominated by Type III kerogen (HI < 200 mg HC/g TOC), and is thus considered to be gas-prone. The analysed Cretaceous source rock samples have vitrinite reflectance values in the range of 0.37–0.95 Ro% (immature to peak-maturity for oil generation).A variety of biomarkers including n-alkanes, regular isoprenoids, terpanes and steranes suggest that the Cretaceous source rocks were deposited in marine to deltaic environments. The biomarkers also indicate that the Cretaceous source rocks contain a mixture of aquatic organic matter (planktonic/bacterial) and terrigenous organic matter, with increasing terrigenous influence in the Late Cretaceous (Mukalla Formation).The burial and thermal history models indicate that the Mukalla and Harshiyat formations are immature to early mature. The models also indicate that the onset of oil-generation in the Qishn source rock began during the Late Cretaceous at 83 Ma and peak-oil generation was reached during the Late Cretaceous to Miocene (65–21 Ma). The modeled hydrocarbon expulsion evolution suggests that the timing of oil expulsion from the Qishn source rock began during the Miocene (>21 Ma) and persisted to present-day. Therefore, the Qishn Formation can act as an effective oil-source but only limited quantities of oil can be expected to have been generated and expelled in the Jiza sub-basin.

Burial estimates constrained by clumped isotope thermometry: example of the Lower Cretaceous Qishn Formation (Haushi-Huqf High, Oman)

Abstract Accurate determination of the thermal history of sedimentary basins is critical to constrain the timing of diagenetic processes. Here, clumped isotope palaeothermometry is used to estimate minimum burial depth of the Lower Cretaceous Qishn Formation in east central Oman. Fossil oysters were collected in a soft argillaceous unit, thin-sectioned, and studied under petrographical and cathodoluminescence microscopy, revealing a variable state of shell preservations with early silica replacement of carbonate and late-stage calcite cementation. Clumped isotopes values varied from 0.602 to 0.666‰, with the best-preserved oyster shell yielding a temperature of 37 ± 4°C and a calculated oxygen isotope ratio in seawater (δ 18 O seawater ) compatible with Cretaceous seawater having experienced moderate evaporation (1.0–1.5‰ VSMOW). The new minimum estimates for the burial depth of the Qishn Formation is 1.0–1.2 km, based on the temperature difference between the well-preserved oyster and the partially neomorphosed oyster recording the highest burial temperature (63 ± 4°C). This is in excess of what was predicted by previous studies (&lt;400 m), but compatible with conodonts alteration index temperatures (&lt;80°C). This study highlights the potential of clumped isotopes as a quantitative tool to estimate temperature and burial depth in fine-grained carbonate succession where fluid inclusions are absent, and offers a new tool to constrain the thermal histories of sedimentary basins.

Sedimentology, rhythmicity and basin-fill architecture of a carbonate ramp depositional system with intermittent terrigenous influx: The Albian Kharfot Formation of the Jeza-Qamar Basin, Dhofar, Southern Oman

The Albian Kharfot Formation is preserved in the eastern margin of the Jeza-Qamar Basin which straddles across the Oman–Yemen border. This study addresses the sedimentological attributes of the formation and deduces its depositional setting, cyclicity and relative sea level changes in local (within the basin) and regional (Arabian) contexts. The interaction among siliciclastic influxes, in-situ carbonate production and tectono-climatic controls on the stacking nature of the various lithofacies that build-up the formation is discussed. In the study area, the formation lies unconformably over Barremian–Aptian Qishn Formation and conformably under late Albian–?Turonian Dhalqut Formation. The Kharfot Formation thickens from ~140m in the eastern side of the study area to ~300m at the Oman–Yemen border. It consists of eight lithofacies: Orbitolina-rich marls, peloidal bioclastic packstone, bioclastic mudstone to wackestone, argillaceous, bioclastic floatstone to rudstone, bioclastic rudstone, sandy, peloidal, bioclastic mudstone to packstone, peloidal, bioclastic grainstone and dolostone. The vertical arrangement of these lithofacies defines recurring meter- to decameter-scale, shallowing-upward units deposited on a westward-deepening inner- to outer-ramp setting. Tectonic rejuvenation of the siliciclastic source area was accompanied by warm, humid climatic conditions as suggested by high kaolinitic marls of the Kharfot Fm. and coeval quartz-rich sandstone units (Harshiyat Fm.). The shallowing-upward rhythmic sedimentation of the formation has close resemblance with cycles of the Nahr Umr Formation in northern Oman and partially comparable with the global sea level changes. The Kharfot basin was an intrashelf depression that was part of the much larger Arabian epeiric platform. The latter is defined by a rimmed margin in northern Oman where Al-Hassanat Formation represents platform margin deposits and Nahr Umr Formation representing back-rim intrashelf depression which received fine-grained siliciclastic influx from the land (westward). In southern Oman where Kharfot Formation accumulated, the platform was unrimmed ramp type basin with high fine clastic influx along with elevated carbonate production.

Diagenesis and reservoir quality analysis in the Lower Cretaceous Qishn sandstones from Masila oilfields in the Sayun–Masila Basin, eastern Yemen

Lower Cretaceous sandstones of the Qishn Formation have been studied by integrating sedimentological, petrological and petrophysical analyses from wells in the Masila oilfields of eastern Yemen. These analyses were used to define the origin, type of diagenesis and its relation to reservoir quality. The sandstones of the Qishn Formation are predominately quartz arenite to subarkose arenite with sublitharenite and quartz wackes displaying a range of porosities, averaging 22.33%. Permeability is likewise variable with an average of 2844.2 mD. Cementation coupled with compaction had an important effect on porosity destruction after sedimentation and burial. The widespread occurrence of early calcite cement suggests that the sandstones of the Qishn Formation lost significant primary porosity at an early stage of its diagenetic history. In addition to poikilotopic calcite, several different cements including kaolinite, illite, chlorite and minor illite–smectite occur as pore‐filling and pore‐lining cements, which were either accompanied by or followed the development of the early calcite cement. Secondary porosity development occurred due to partial to complete dissolution of early calcite cements and feldspar grains. The new data presented in this paper suggest the reservoir quality of Qishn sandstones is strongly linked to their diagenetic history; hence, the reservoir quality is reduced by clay minerals, calcite and silica cements but is enhanced by the dissolution of the unstable grains, in addition to partial or complete dissolution of calcite cements and unstable grains. Copyright © 2015 John Wiley &amp; Sons, Ltd.

Dolomitization of Lower Cretaceous Peritidal Carbonates By Modified Seawater: Constraints From Clumped Isotopic Paleothermometry, Elemental Chemistry, and Strontium Isotopes

Abstract This study investigates one of the few examples of dolomitization of Lower Cretaceous shallow-water limestones from the southern Tethys carbonate platform from outcrops on the Haushi-Huqf High in central-east Oman. Mud-dominated peritidal carbonates rich in microbial mats are replaced by fine crystalline dolomite along at least 60 km in the lower 10 m of the Jurf Formation. Two, meter-thick beds in the overlying Qishn Formation are also dolomitized over lateral distances of one to two kilometers. The stratabound geometry and petrographic relations of the dolomite with all other diagenetic phases indicate that the dolomite precipitated early. The presence of only rare anhydrite relicts suggests that seawater was below gypsum saturation during most of the dolomitization, supporting the hypothesis that Cretaceous slightly evaporated water (δ18Ofluid values range from 2.8‰ to 3.5‰ SMOW) can affect pervasive dolomitization. Despite being composed of peritidal facies with features suggesting high salinity, most of the carbonate succession was not dolomitized, suggesting that the presence of microbial mats exerted a major control on the distribution of dolomite, and that salinity is only a minor control on dolomitization. Clumped-isotope results indicate that the early formed dolomite re-equilibrated with fluids at 44 ± 3°C in a shallow-burial setting. The elevated iron content (on average 6011 ppm) and 87Sr/86Sr (on average 0.70782) with respect to Cretaceous seawater suggests that the burial fluids interacted with Permian clay and feldspars of the Gharif Formation that underlies the Cretaceous carbonates. The vertical gradients of radiogenic Sr and the occurrence of small volumes of coarse crystalline dolomite in stylolites and fractures suggests that burial fluids were driven vertically and laterally by differential compaction, probably during maximum burial in the Late Cretaceous.

Stratigraphic evolution and depositional system of Lower Cretaceous Qishn Formation, Dhofar, Oman

Abstract The Barremian(?)–Aptian Qishn Formation of Dhofar (Oman) is represented by eastward (landward) thinning strata that onlap Marbat palaeohigh basin margin. The formation includes Shabon, Hinna and Hasheer members, in ascending order. The Shabon Member consists of massive and cross-bedded, locally conglomeratic arkose and quartzarenite. The Hinna Member has a lower part of rhythmically arranged bioclastic wackestones/mudstones that grade to fine crystalline dolomudstone and an upper part of cyclic units of nodular, marly, rudistic floatstone/rudstone lithofacies capped by normally grading, intraclastic, bioclastic packstone/grainstone lithofacies. Mudcracks, teepee structures and microbial laminations occur in the lower part. The member terminates with 10-m-thick discoidal orbitolinid- and rudist-bearing marls envisaged as the deepest facies of the formation. The Hasheer Member consists of partly dolomitized strata of bioclastic packstones, grainstones and rudstones. Cross-bedding and erosional surfaces are present. The overall depositional system of the formation evolved from high-energy clastic-dominated, marginal marine environment through tidal carbonate mudflat and lagoonal setting to high-energy carbonate sand shoals. The overall stratigraphic arrangement of the formation suggests a third-order transgressive-regressive system with superimposed fourth- and fifth-order cycles. Shabon and Hinna members represent lowstand to transgressive systems tracts whereas Hasheer Member represents highstand to falling stage systems tracts. Terminal platform-wide exposure resulted in an unconformity at the Qishn–Kharfot contact.

Log-derived petrophysical characteristics and oil potentiality of the Upper Qishn Clastic Member, Masila Basin, Yemen

The Lower Cretaceous Qishn Formation at Masila Basin, Yemen, contains substantial amounts of proven crude oil. It is divided into a lower shaly silisiclastic member and an upper carbonate member. In the present work, detailed formation evaluation of the Upper Qishn Clastic Member was carried out using the digitized well logging data from 12 wells, via computer-assisted analysis, to accomplish its reservoir characteristics and oil potentiality. Accordingly, the true resistivity (Rt), porosity (total φt and effective φe), shale content (Vsh), permeability (K), water saturation (Sw), hydrocarbon saturation (Sh) (movable “Shm” and residual “Shr”) and lithologic composition in each well were estimated, analyzed, and illustrated versus depth on litho-saturation cross-plots. Likewise, the areal distribution of such parameters alongside the member in the investigated area and their relations to geological setting were defined from the constructed isoparametric contour maps. Based on the obtained results, the components of Upper Qishn Clastic Member of Masila Basin are mainly shaly sandstone and minor calcareous sandstone with considerable amount of shale. Regionally, the Member was deposited on an inner neritic to shallow-marine platform setting. It is interpreted as a good-quality reservoir rock which has been established from high total porosity (15–22 %), good effective porosity (8–13 %), and variable shale volume (24–31 %). A number of high hydrocarbon saturation zones (exceeding 55 %) are detected through intervals having Sw 20 % which have been considered as economic oil producers. The storage and pay capacities of the reservoir intervals have been resolved. The obtained results were confirmed from the available data of core analyses and production tests. The Upper Qishn Clastic Member reveals promising reservoir characteristics which should be taken into consideration during future development of the oilfields in the area.

3D geomodeling of the Lower Cretaceous oil reservoir, Masila oil field, Yemen

Oil was first discovered in the Masila area of Yemen in the late 1990s, with about 90% of the reserves found in the Lower Qishn Clastic Member of the Qishn Formation. The porosity determinations of the Lower Qishn Clastic are relatively high and the permeability ranges from 103 to 374 md. This paper tries to evaluate the hydrocarbons in the porous zones encountered in the Lower Cretaceous formations, which were penetrated by the eight wells in the study area. The water saturation shows low values, while the hydrocarbon saturation is in a reverse relation, i.e., the hydrocarbon increases where the water saturation decreases. Different cross-plots such as Rho-PHIN, Rho-DTN, and M-N were used in lithological identification for the two studied formations (Saar and Qishn) in the studied wells. Formation evaluation and presentation forms of the obtained petrophysical parameters have frequently proven that the formations have high hydrocarbon saturation in this area and contain many pay zones. On of the main targets of this paper is to build a detailed 3D geological modeling of the Lower Cretaceous Sequence conducted through an integrated study.

Stratigraphy, deposition, and structural framework of the cretaceous (review) and 3D geological model of the lower cretaceous reservoirs, Masila oil field, Yemen

The Masila area is located in the Hadhramaut region in east central Yemen. Oil was first discovered in the area in late 1990 with commerciality being declared in late 1991. Oil production began in July 1993. By the end of December 1999, the daily production rate was set at 210,000 stock tank barrels/day (STB/D) of very low gas–oil ratio (GOR) oil under partial to full water drive. About 90% of the reserves are found in the Lower Qishn Clastics Member of the Qishn Formation. This paper focuses on the detailed 3D geological modeling of the Lower Cretaceous Sequence conducted through an integrated study. There are three critical areas in the process of modeling reservoirs that involve geological and geophysical modeling, reservoir characterization, and reservoir flow modeling. This paper presents methodologies found useful during the modeling of these reservoirs including field case histories for the Lower Cretaceous reservoir in the Masila oilfield.

Stratigraphic and regional distribution of fractures in Barremian–Aptian carbonate rocks of Eastern Oman: outcrop data and their extrapolation to Interior Oman hydrocarbon reservoirs

The carbonates of the Barremian to Aptian Qishn Formation are outcrop equivalents to major hydrocarbon reservoirs in the Middle East and in Oman specifically. The rocks are exposed in the Haushi–Huqf area of eastern Oman where they are affected by pervasive jointing and localized folding and faulting. Information gathered in the Huqf outcrops can be used to formulate predictions on fracture patterns in adjacent reservoirs. Systematic joints are confined to few meters-thick intervals of widely differing lithologies, which can be correlated over hundreds of square kilometers. Over the entire area, systematic joints are typically more than tens of meters long, have spacings of 4–18 cm and homogeneous morphologies. These joints are interpreted to be of Late Aptian age. The dominant set of joints strikes consistently NW–SE and developed parallel to the causative maximum horizontal compression SH. The direction of compression is at an high angle to the two major tectonic domains of the region, the subsiding Oman Interior basins and the elevated Haushi-Huqf High. NW–SE compression is proposed to have caused crustal/lithospheric buckling and thereby to have controlled Jurassic to Early Tertiary patterns of vertical movements. In such a scenario, the direction of compression is predicted to be constant over the entire domain. It is thus expected that Qishn carbonates in the subsiding Oman Interior basins also experienced NW–SE compression and developed systematic joints similar to those observed in the Huqf region. In the Neogene, with the establishment of the “Zagros” stress field, the maximum horizontal compression became roughly N–S, thereby possibly leading to the closure of pre-existing joint systems.

Characterization, lateral variability and lateral extent of discontinuity surfaces on a Carbonate Platform (Barremian to Lower Aptian, Oman)

AbstractHiati of various duration in carbonates are commonly expressed as discontinuity surfaces. The understanding of processes that form and affect these surfaces leads to an improved sequence‐stratigraphic interpretation, a reliable outcrop correlation, and better models for reservoir compartmentalization. Various intraformational discontinuities were analysed and interpreted in a well‐exposed study window, 2·5 km in lateral length and 60 m in height comprising the Barremian‐Aptian Qishn Formation (Haushi‐Huqf area, central Oman). This study focuses on the lateral extent and morphology of the surfaces, the petrography of the underlying rocks, and the facies changes and geochemical trends across these discontinuities. Furthermore, the lateral variability of discontinuity surfaces was documented. Three genetic types of discontinuities are differentiated: (i) erosion surfaces; (ii) omission surfaces (hard‐ and firmgrounds); and (iii) composite surfaces with evidence for both subaerial exposure and submarine boring. Field observations, combined with petrographic and geochemical data, suggest that 17 surfaces are laterally extensive for at least 20 km and record relative sea‐level fluctuations of regional scale. In contrast, a large number of laterally limited surfaces (&lt;1 km) are related to locally active processes such as waves and current erosion. The lateral variability along extensive surfaces is the result of the depositional environment below the discontinuity, the sea‐floor topography, waves and currents and differential erosion. The most pronounced lateral variability is present along six laterally extensive composite surfaces that record terrestrial exposure and subsequent flooding of a tidal flat environment. This variability is caused by spatial variability in the tidal flat environment, meteoric alteration and differential erosion. This study emphasizes the spatial and temporal complexity of processes that form and modify discontinuity surfaces. This variability must be kept in mind when interpretations and correlations are based on one‐dimensional sections or cores.

Horizontal Water Disposal Well Performance in a High Porosity and Permeability Reservoir

Abstract Nexen Petroleum International Ltd. (Nexen) has a 52% interest and is operator of the Masila Block in the Republic of Yemen. Oil and water are produced mainly from the under pressured Qishn Formation, a non-marine to marine clastic sequence of Lower Cretaceous Age, which is roughly 61 m (200 ft) thick and lies at a depth of 191 m (5,500 ft) from surface. Currently, oil production is 36,567 m3/d (230,000 BOPD) at a water cut of about 80%. The 160,000 m3/d (1.0 MMBWPD) of water produced are currently reinjected under matrix injection pressures into 24 vertical and four horizontal wells. These are completed in the best quality sands (the S2/S3 members of the Upper Qishn Formation) that have average porosity and permeability of 20% and 3.65E-12 m2 (3,700 md), respectively. Despite the exceptional disposal reservoir quality, injection problems continue to exist that have caused Nexen to study and evaluate numerous methods of improving injectivity. After xtensive laboratory core and field testing, hypotheses have been developed to explain the behaviour of the water disposal wells including the so-called "check valve effect." Horizontal wells and proppant fractured wells were employed to test the hypotheses and to improve injectivity. This paper reviews the laboratory results and discusses the placement of horizontal injectors along with the drilling and completion details of the wells. The performance of the horizontal disposal wells under matrix injection is compared to conventional vertical disposal wells and proppant fractured vertical wells. Produced water is expected to reach 238,500 m3/d (1.5 MMBWPD) and improvements in disposal well performance will reduce the number of wells that will need to be drilled to handle this volume, thereby improving overall project value. Introduction The Masila Block in the Republic of Yemen is operated by Nexen Petroleum International Ltd. on behalf of its partners: Occidental Petroleum Ltd., Consolidated Contractors Company S.A.L., and the Government of the Republic of Yemen. Oil production from the block began in 1993 and current field oil, gas, and water production rates average 36,567 m3/d (230,000 BOPD), 200,000 m3/d (7 MMSCFD), and 160,000 m3/d (1,000,000 BWPD), respectively. Figure 1 shows the location of the 15 main producing fi elds, the central processing facility (CPF) and the hydrocyclone installations at main producing fields. These hydrocyclones are used to achieve initial separation of oil from water at the individual pools remote from the CPF. The operation of the Masila project is described in an earlier paper with particular attention paid to disposal of produced water(1). The majority of oil produced to date has been from the Upper Qishn Formation, which is supported by a strong natural water drive. Other producing horizons include the Lower Qishn clastics, Upper Saar clastics, Saar carbonate, Madbi limestone, Basal sand, and the fractured granitic Basement (Figure 2). Most produced water is currently reinjected into the S3 and S2 members of the Upper Qishn Formation, and it is therefore worthwhile to review the geology of these two members. The S3, at the base of the Upper Qishn Formation, is an amalgamated fluvial channel sequence.

Barremian-lower Aptian Qishn Formation, Haushi-Huqf area, Oman: a new outcrop analogue for the Kharaib/Shu’aiba reservoirs

ABSTRACT Limestones of the middle Cretaceous Qishn Formation are exposed in the Haushi-Huqf area of Oman. These carbonates preserved reservoir properties due to shallow burial and an arid post-exhumation climate. This characteristic makes the Qishn Formation an excellent outcrop analogue for the Upper Kharaib and Lower Shu’aiba oil reservoirs in the Interior Oman basins. The aim of this paper is to provide a broad overview of results from an industry-oriented field study recently performed in the Qishn Formation outcrops belts. The comparison of these results with studies undertaken in the Northern Oman Mountains and the Oman Interior subsurface is the topic of ongoing research. The age of the Qishn Formation is middle Barremian to mid-early Aptian, the Hawar Member (equivalent) is earliest Aptian in age. The paleo-environments recorded range from the tidal mudflat to the argillaceous platform setting (outer ramp) below the storm wave base. In terms of sequence stratigraphy, four large-scale transgressive-regressive cycles of Cretaceous age (Jurf and Qishn formations) were distinguished. Sequence I, a dolomitized succession termed Jurf Formation, is the equivalent of the Lekhwair, the Lower Kharaib and possibly older Cretaceous units. Due to pervasive early dolomitization, the Jurf Formation is not further considered here. Sequence II, forming the base of the overlying Qishn Formation represents the equivalent of the Upper Kharaib, portions of Sequence III the Hawar Member, and Sequence IV is the equivalent of the Lower Shu’aiba. At least two lower orders of cycles are superimposed on these four sequences. Total porosity with a mean of 19.3% (s = 8.74%) and permeability with a mean of 6.36 mD (s = 6.57 mD) characterize the Qishn Formation limestones. Overall, the correlation of porosity and permeability is better for regressive (highstand) deposits than for the transgressive limestones. The lateral variability (&amp;gt;100 m) of porosity and permeability values within specific intervals is substantial and matches or even exceeds stratigraphic variability. Spectral gamma ray logs from Qishn Formation recorded in the outcrops are dominated by the U spectrum and to a lesser degree by the Th spectrum. Qishn Formation carbonates in the Haushi-Huqf High are extensively fractured. The outcrops studied display very widespread systematic jointing with dominant NW-SE to WNW-ESE trends. A second, subordinate system results in a potentially highly interconnective network. Joints are strictly confined to specific beds or groups of beds and have regular spacing of between 6 and 18 cm. Joints are related to regional stress fields and do not show significant changes (in density or direction) in the vicinity of folds or faults. Faults are typically organized in corridors consisting of up to several metre-wide zones with swarms of discrete fault planes. Fault gauges are very rarely observed, but where present, form discontinuous, 10s of cm long lenses.

Tide-influenced sedimentation in a rift basin—Cretaceous Qishn Formation, Masila Block, Yemen: A billion barrel oil field

The Lower Cretaceous Qishn Clastics Member in Masila Block 14, Hadhramaut region, Republic of Yemen, has estimated reserves of 1.1 billion bbl recoverable oil and has produced 600 million bbl of oil. Sedimentation took place in an elongate paleogulf of the Say'un-al Masila basin, with open-marine carbonates to the east. The Qishn Clastics Member unconformably overlies mixed carbonates and clastics of the Sa'af Member. Lower Qishn onlap resulted in deposition of brackish and tidal (likely macrotidal) estuarine to open-bay or gulf deposits. The middle portion of the lower Qishn Clastics Member shows evidence of arid nonmarine sedimentation, including debris-flow deposits, red beds, and shale-clast conglomerates, in turn, overlain by interfingering coastal and nonmarine deposits. The lower Qishn Clastics Member is truncated by a sequence boundary overlain by an extensive sandstone deposited in a low-accommodation braid plain close to the shoreline. A flooding surface is present at the top of the sandstone, over which progradational, tide-influenced deltaic strata were deposited. Delta progradation culminated in shallow-water clastic dolomitic deposits on the coastal plain. With subsequent transgression, a rising water table caused a nonmarine flooding surface with lakes and lacustrine deltas, overlain by tidal-flat deposits. Ongoing transgression resulted in wave ravinement overlain by shallow-shelf clastics and then deposition of slightly deeper shelf carbonates. The uppermost unit comprises bioturbated, clastic-shelf deposits related to a drop in relative sea level. Throughout much of the Qishn Clastics interval, accommodation was moderate, except for low accommodation associated with regional sheet sandstone at the base of the upper Qishn Clastics Member. Virtually all marine and brackish deposits show evidence of tidal sedimentation. Climate was arid and seasonally wet.