Ahmad, Khalid (Kuwait Oil Company) | Ferdous, Hasan (Kuwait Oil Company) | Llerena, Javier (Kuwait Oil Company) | Ahmad, Fatma (Kuwait Oil Company) | Chaudhary, Pradeep (Kuwait Oil Company) | Abbas, Faisal (Kuwait Oil Company) | Sammak, Ibrahim (Kuwait Oil Company)
One pilot study presently being conducted through CSS thermal recovery technology to explore a shallow poorly-consolidated viscous oil bearing sandstone reservoir in Kuwait with extensive integrated reservoir evaluation efforts to optimize the future development strategy.
The reservoir largely consists of two separate deltaic sand packages representing multi-stacked channel facies resulting to stratified reservoir intervals with variable degree of fluid saturations. Reservoir characterization uncovers high matrix contents along with calcite, dolomite, and clays as cements which essentially control uneven pore-geometry that fabricate the petrofacies types into multiple thin stratified-pay intervals, each being < 30' thick with variable fluid saturations resulting from long transitional thief zones posing high risk for thermal recovery. Thus, a seemingly simple channel-based reservoir interval has been greatly altered by diagenetic episodes that need evaluation towards an arduous perforation, completion and production strategy to pursuit the well-defined individual thin pay-interval.
Single-well thermal recovery scheme under "injection-soak-production?? sequence being conducted presently in three vertical wells, each subjected to first cycle injection of moderate quality steam (~75% at 4200 F) at rates 400 to 600 barrels EW/d at about 450 psig injection pressure for 26 to 71 days, followed by a soak period of 10 to 60 days. Subsequent total production estimates SOR between 0.2 and 0.9. In two wells, cumulative oil/water productions and 15% to 34% water cut indicate an excellent response to thermal stimulation. The encouraging injection parameters of steam slug size, high injection rates at low pressures, and subsequent productions provide valuable information towards upcoming second cycle injection and future steam flood strategy.
The ongoing CSS pilot is providing some critical information for the future commercial development phase. As such, all pertinent data are closely evaluated to ensuring the optimal strategy to meet the long-term development plan for this viscous oil asset.
Three significant source rocks are present beneath much of the Alaska NorthSlope (Fig. 1), the Triassic Shublik Formation, the lower part of theJurassic-Lower Cretaceous Kingak Shale, and the "Brookian shale" that includesthe Cretaceous pebble shale unit and Cretaceous-Lower Tertiary Hue Shale.Although these source rocks are known to have generated oil and gas thatmigrated into conventional accumulations, including the super-giant Prudhoe Bayfield, the first attempt to produce hydrocarbons directly from the three sourcerocks was initiated in 2012.
The Shublik Formation contains a mixture of Type I and IIS kerogen, and oilin conventional accumulations sourced from the Shublik is of relatively lowgravity (23-39° API) and high sulfur (more than 1.5 percent). In contrast, theKingak and Brookian source rocks contain a mixture of Type II and III kerogen,and oil in conventional accumulations sourced from those rocks is of relativelyhigh gravity (35-42° API) and low sulfur (less than 0.3 percent). These threesource rocks occur at depths that range from less than 3,000 feet along theBarrow Arch to more than 20,000 feet in the Brooks Range foothills. Over thatrange of depth, thermal maturity of the source rocks grades from the onset ofoil generation along the Barrow Arch, through the oil window, and well into thedry gas window in the south (Fig. 1).
Shale-oil and shale-gas assessment units (AUs) - areas where organic richfacies are inferred to be in the oil or gas window, respectively - weredelineated for each source rock (Figs. 2, 3, 4) based on empirical thermalmaturity data and regional modeling (Houseknecht et al., 2012a). Both Shublikand Brookian source rocks include rock types that are brittle and in whichnatural fractures are common. Brittle lithologies include limestone, phosphaticlimestone, sandstone, siltstone, and chert in the Shublik and very-fine-grainedsandstone, siltstone, concretionary carbonate, and silicified tuff in theBrookian. In contrast, the Kingak source rock is mostly clay shale that deformsplastically, and brittle lithologies generally are absent. These petroleumsystem elements (organic matter content, thermal maturity, and brittlelithology) were among the factors considered in estimating the probability thatoil and gas can be technically recovered from the source rocks, with results of95 percent probability for the Shublik, 90 percent for the Brookian, and 40percent for the Kingak (Houseknecht et al., 2012b).
Maps of petroleum system elements were used to evaluate spatial variabilityin source rock character. A map of mostly transgressive facies in the ShublikFormation (Fig. 2) delineates areas that may contain highest organic content,based on published relations between transgressive facies and total organiccarbon (TOC) in the formation (Hulm, 1999; Robison and Dawson, 2001; Peters etal., 2006; Kelly et al., 2007). The Shublik is absent owing to non-depositionat Pt. Barrow and transgressive facies in the formation thicken basinward in aradial pattern, reaching maximum values greater than 200 ft in northeastern andwestern NPRA (Fig. 2). East of NPRA, the Shublik thins depositionally towardsPrudhoe Bay, and is truncated completely farther east beneath the LowerCretaceous unconformity (Fig. 2). In northcentral NPRA, Shublik transgressivefacies are not only relatively thin (less than 100 ft) but also containgenerally low organic carbon content (Fig. 2) and low values of interpretedoriginal hydrogen index (Peters et al., 2006). Both the TOC content (Fig. 2)and interpreted original hydrogen index (HI) increase abruptly in the vicinityof Teshekpuk Lake in northeastern NPRA, and both parameters are relatively higheastward to the Shublik truncation edge beneath the eastern North Slope(Peterset al., 2006). We infer that the best oil potential in the Shublik occurswithin the shale-oil AU (defined by thermal maturity) from Teshekpuk Lakeeastward (Fig. 2). We infer good gas potential in the Shublik in the shale-gasAU across much of the North Slope (Fig. 2).
The Kingak Shale is divided into three map areas (Fig. 3) on the basis ofseismic and well-log character (Houseknecht and Bird, 2004). A broad area innorth-central NPRA contains a series of progradational shelf sequences, withinwhich Kingak source-rock facies are mostly limited to thin transgressivedeposits characterized by low values of TOC and HI. To the east and southeast,shelf deposits are absent and the lower Kingak comprises basinal condensedshale that has higher values of TOC and HI (Houseknecht and Bird, 2004; Peterset al., 2006). The Kingak is poorly known beneath the southwestern North Slopebecause of an absence of well penetrations (Fig. 3). We infer that the best oiland gas potential in the Kingak occurs within the shale-oil and shale-gas AUs,respectively, and basinward from the shelf sequences in north-central NPRA(Fig. 3). However, the paucity of brittle facies in the lower Kingak Shale maylimit its reservoir quality everywhere.
A map of the Brookian sequence showing thickness of net high gamma-ray (HGR)log response (cumulative thickness of gamma-ray response greater than 150 API)in the oil window (based on thermal maturity) delineates thermally mature areasthat may contain higher organic content (e.g., Schmoker, 1981). The map of netHGR displays complex patterns that reflect regional accommodation, localerosion beneath sequence-bounding unconformities, and thermal maturitypatterns. In general, net HGR thickens to the east (Fig. 4); this regionaltrend is consistent with patterns of TOC and interpreted original HI (Peters etal., 2006). Brittle facies closely associated with HGR intervals in theBrookian are more common east of NPRA. We therefore infer that the best oilpotential in the Brookian shale occurs in areas that contain more than 100 ftof HGR in the oil window, east of NPRA and west of ANWR (Fig. 4). The best gaspotential likely occurs within the shale-gas AU, in areas adjacent to the TransAlaska Pipeline System where the largest thickness of HGR is observed (Fig.4).
The USGS in 2012 completed the first-ever assessment of technicallyrecoverable shale-oil and shale-gas resources in northern Alaska. Aggregateestimates for all three source rocks range from 0 to 2 billion barrels of oiland 0 to 80 trillion cubic feet of gas (TCFG), with the ranges representing a95- to 5-percent probability of occurrence (Houseknecht et al., 2012b).Estimates for each source rock system include 0 to 928 million barrels of oil(MMBO) and 0 to 72 TCFG for the Shublik, 0 to 955 MMBO and 0 to 4 TCFG for theBrookian, and 0 to 117 MMBO for the Kingak (gas was not quantitatively assessedfor the Kingak). In all cases, the zero value at the 95-percent probabilityreflects the application of play-level risk. The Shublik is estimated tocontain the greatest oil and gas resource potential per unit area, with valuesthat rank among the top few source-rock systems in the United States.
Poedjono, Benny (Schlumberger) | Beck, Nathan (Schlumberger) | Buchanan, Andrew (Eni Petroleum Co.) | Brink, Jason (Eni Petroleum Co.) | Longo, Joseph (Eni Petroleum Co.) | Finn, Carol A. (U.S. Geological Survey) | Worthington, E. William (U.S. Geological Survey)
Geomagnetic referencing is becoming an increasingly attractive alternativeto north-seeking gyroscopic surveys to achieve the precise wellbore positioningessential for success in today's complex drilling programs. However, thegreater magnitude of variations in the geomagnetic environment at higherlatitudes makes the application of geomagnetic referencing in those areas morechallenging.
Precise, real-time data on those variations from relatively nearby magneticobservatories can be crucial to achieving the required accuracy, butconstructing and operating an observatory in these often harsh environmentsposes a number of significant challenges. Operational since March 2010, theDeadhorse Magnetic Observatory (DED), located in Deadhorse, Alaska, was createdthrough collaboration between the United States Geological Survey (USGS) and aleading oilfield services supply company. DED was designed to produce real-timegeomagnetic data at the required level of accuracy, and to do so reliably underthe extreme temperatures and harsh weather conditions often experienced in thearea.
The observatory will serve a number of key scientific communities as well asthe oilfield drilling industry, and has already played a vital role in thesuccess of several commercial ventures in the area, providing essential,accurate data while offering significant cost and time savings, compared withtraditional surveying techniques.
Stoupakova, A.V. (Moscow State University) | Kirykhina, T.A. (Moscow State University) | Suslova, A.A. (Moscow State University) | Kirykhina, N.M. (Moscow State University) | Sautkin, R.S. (Moscow State University) | Bordunov, S.I. (Moscow State University)
The Russian Western Arctic Basins cover the huge area including the Barentsand Kara seas, the western part of the Laptev sea and adjacent territories withsome archipelagoes and islands (Spitsbergen, Franz Josef Land, SevernayaZemlya, Novaya Zemlya, etc.). They comprise the Barents and Kara Basins, thenorthern areas of the Timan-Pechora Basin, the North West Siberia, includingYamal and Gidan peninsulas and the Yenisey-Khatanga Basin. Within the RussianWestern Arctic basins the following main tectonic elements can be identified:extensional depressions (Central-Barents, Yenisei-Khatanga, West Siberia, EastUrals) with sedimentary thickness is more than 12- 14 km; platform massiveswith average thickness of sediments of 4 - 6 km, monoclines and tectonic steps,like transition zones between extensional depressions and platform massives.Western Arctic basins are filled by mainly Palaeozoic and Mesozoic sedimentarysuccessions. In the sedimentary cover of this large region, many commonstratigraphic complexes and unconformities can be traced within Palaeozoic andMesozoic complexes that show similarity of geological conditions of theirformation. Analysis of the Russian Western Arctic basins, their structures andhydrocarbon prosepctivity shows the areas, which are favourable for hydrocarbonaccumulations. Deep depressions, as areas of long-term and stable sinking, arehighly promising zones for the accumulation of predominantly gas fields. Theyform regional gas accumulation belts, extending for thousands of kilometres,where the largest fields can be expected in the zones of their intersectionwith the major tectonic elements of another strike. Within the Barents-Karashelf, the large belt of predominantly gas accumulation extends from the northof the West Siberian province through the South Kara basin and into the BarentsSea. The second potential belt of predominantly gas accumulation may beassociated with the North Barents ultra-deep depression. On the flanks of thedepressions the sedimentary cover profile does not contain the complete set ofoil-and-gas-bearing complexes, identified in the central parts of theextensional depressions. The reservoirs can be filled by HC due to the lateralmigration of fluids from the neighbouring kitchens or from their own dominantoil-and-gas source rock strata. For the formation of oil accumulations, themost favourable are platform massifs and ancient uplifts areas.
Facies and their distribution in space are key building blocks to determine the depositional architecture of hydrocarbon reservoirs. For this reason, the unified high resolution facies and sequence stratigraphy boundaries are needed to constrain facies architecture and their properties distribution for constructing the 3D static and dynamic model. A comprehensive facies analysis and modeling within the established stratigraphic framework, was conducted to reduce the uncertainty in correlating and building-up the architecture between wells.
Over 30,000ft of core data from 155 wells and their log data are used in integration with the seismic interpretation. Knowledge of the facies results in a better correlation, used then to generate a total of 47 spatial facies maps. Some facies are combined to facies associations (FA) maps, representing the FA at each sequence boundary in its sequence package. For each selected interval, the dominant FA observed in individual wells has been correlated; preserving the general evolution of the depositional environment and the sequence stratigraphy framework. These maps are used to constrain the variograms for the petrophysical properties distribution in terms of orientation and ranges.
A conceptual facies model was created based on facies distribution following an evolving platform to basin topography during transgressive (Apt1&Apt2), early-highstand (Apt3), late-highstand (Apt4a&Apt4b), and composite lowstand (Apt5) phases of carbonate platform development during the Aptian. The best reservoir quality is dominated by dissolution related mouldic and vuggy macropores. The grain supported textures demonstrate better overall reservoir quality as a result of more abundant interparticle and intraparticle pores and enhanced macro-vuggy porosity created by leaching process. Some poor reservoir quality is observed in grainy facies due to cementation.
A detailed understanding of the core-based facies description/analysis is required for identifying the reservoir properties and its relation to rock-texture; leading consequently to the rock-flow-units in the dynamic model.
In 2010, Qatar Shell Upstream International B.V. (QSUI) re-entered Exploration in Qatar focusing on the relatively deep conventional Pre-Khuff gas plays with a view to discover additional hydrocarbons in the State of Qatar. The Pre-Khuff plays pose two main challenges; firstly the geophysical challenge of being able to image the deep Pre-Khuff structure and hence trapping configurations and secondly the geological challenge of being able to realistically predict reservoir and top seal quality. This paper highlights the approach to geological issues associated with Pre-Khuff exploration and how technologies were deployed to address pre drill exploration challenges in the venture.
Significant uncertainty exists in relation to the deep structure of the Qatar Arch particularly when in the region the Pre- Hercynian package has been shown to be structurally different to the overburden. 2D seismic reprocessing has helped to significantly improve seismic imaging encompassing clear improvements in seismic data quality with better reflector continuity and elucidation of structural and stratigraphic complexity. The overall structure of the Qatar Arch and the trap styles in the Pre-Khuff are assessed using a combination of gravity anomaly data and interpretation of 2D seismic profiles, while incremental restoration of 2D seismic lines provides insight on the timing of trap formation.
The Devonian Jauf and the Permo-Carboniferous Unayzah plays are primary targets in Block D. Key petroleum system risks are taken as top seal retention, reservoir quality and charge timing and migration. To address these geological factors, data has been re-assessed and new work undertaken on stratigraphic definition, depositional models, reservoir quality prediction, integrated charge evaluation and seal integrity of the Pre-Khuff. Pre-Khuff top seal effectiveness in the focus plays have been assessed through MICP analysis and demonstrates that the relevant seals can hold back significant gas columns. Revised depositional models, based on core observations, have been used to extend potentially successful play fairways into Qatar. New petrographic analysis programs address the diagenetic controls on reservoir quality and their relationship with depositional environments aiding the prediction of potential net viable reservoirs at depths greater than conventional cementation floors. Integrated charge evaluation using basin modeling and geochemical techniques comprising Compound Specific Isotope, TOC, visual kerogen and chitinozoan reflectance analysis suggests a working petroleum system for Pre-Khuff reservoirs. 1D basin models suggest the Pre-Khuff on the Qatar Arch has received gas charge over the last 100 Ma but despite these favorable conditions, a key risk remains the presence of effective vertical migration pathways (i.e. faults) from the source rock into the prospective reservoirs.
The pre-Khuff principal hydrocarbon reservoir, Unayzah Formation, consists mainly of distal braid plain sandstones characterized by aeolian and sabkha facies with minor fluvial units. It extends between the pre-Khuff and the Hercynian unconformities. In Abu Dhabi, the Unayzah-A is further subdivided into three members, Members 1 and 2 are comprised of sandstone reservoirs and Member 3 consists of siltstone and shale sediments.
Facies controls on reservoir quality are weak. The main controls on porosity reduction of the reservoir are mechanical compaction and silica cementation. Quartz cementation tends to be the most severe in the cleanest, coarsest sandstones and near certain fractures. The presence of clay mineral grain coatings, although reducing the permeability, but locally protects the rock from secondary quartz overgrowth and preserve the porosity to great depths of burial. Without the grain coating, porosity will decrease with depth until the reservoir rock is completely tight.
Unayzah reservoir seals are provided by the Basal Khuff Clastics, tight Basal Khuff Carbonate and Middle Khuff Anhydrite. The Basal Khuff Carbonate seal does not appear to be regionally extensive but localized and potentially prospect specific. However, there are insufficient data to accurately define the seal for the Unayzah hydrocarbon accumulations.
Due to lack of deep penetrations in Abu Dhabi, basin modeling for Silurian hot shale source rock is challenging. Therefore, much of the unknown source and tectonic information were derived from the surrounding countries. This comes from understanding the regional tectonics and depositional trends of the southeastern Arabian plate, which helped to extrapolate the source trends into the Abu Dhabi area. The basin model shows that oil from Silurian source rock was generated early in the basin history and was widespread by the Late Triassic (220 Ma). Significant gas generation occurred during Lower Cretaceous (140 Ma) and dominated the hydrocarbon system by Middle Cretaceous (110 Ma). During the Early Tertiary (50 Ma), the source rock was highly mature for gas generation and at present-day, the charge is still active in the north offshore of Abu Dhabi.
The pre-Khuff charge history showed that the southern offshore and onshore structures are underfilled. The filling of these structures ranges between 50% and 80%, but in some onshore structures the filling is less than 50%. The middle and northern offshore structures are expected to be filled to spill point.
The Unayzah Formation in Abu Dhabi forms a potential target for future gas exploration. Many structures remain to be drilled especially in offshore Abu Dhabi and some of these prospects, may contain significant volumes of gas.
The facies variation, depositional environment, reservoir properties, and hydrocarbon potential of the Unayzah Formation were evaluated using data from key wells that are distributed over all Abu Dhabi (Figure-1). The data used in Unayzah evaluation included logs, drilling reports, selected cores and regional seismic lines. The available basin modeling results were incorporated into this evaluation. The Paleozoic basin modeling not only describes the maturation history of the Qusaibah source rock, but also predicts the filling percentage of the Abu Dhabi prominent fields.
Middle Triassic to Early Jurassic formations were not previously considered as exploration objectives. Only a limited wells penetrate these formations and most of these wells were targeting the deeper Khuff and pre-Khuff reservoirs. Stratigraphically, the section is comprised of sequences of shallow marine mixed carbonates intercalating with shale, sandstone and anhydrite streaks. These formations, although they exhibit gradual thickening from the north towards the south direction, yet they show remarkable lateral consistency, both in lithology and log response. Primary and secondary porosity are generally poor in these formations, reflecting the deep burial depth and the intercalation of shale and anhydrite beds with the carbonate reservoirs. Structurally, the formations have been subjected to numerous phases of tectonic deformation that have affected the facies variations and reservoir development. Evidence indicates that the early phase of Qatar Arch development and the southeast Mender palaeohigh were tectonically active during the Triassic time.
The Lower Jurassic and Upper Triassic formations have discontinuous and moderate source rock development. Sapropelic kerogen constitutes the dominant type of organic matter, however, also humic type is present but in minor quantities (Lutfi, 1987; Hassan, 1989). The top Triassic maturation modeling showed various degrees of thermal maturation ranging from mature to intensively mature stages. Interpretation of the maturation regime indicated that most of onshore Abu Dhabi is in the dry gas generation window. The southern offshore area is within the wet gas generation, while the northern offshore is still in the oil generation window. The relatively lean source rock intervals found within the Lower Jurassic and Triassic Formations suggest that there is a significant charge contribution from the deeper Silurian Hot Shale source rocks.
Pronounced gas shows were experienced while drilling some of the offshore and onshore structures. The well data indicates that the Izhara, Hamlah, Minjur and Marrat Formations are developed in onshore Abu Dhabi. Sedimentary patterns, facies variations and log response of the Lower Izhara, Minjur and possibly Upper Gulailah Formations suggest the presence of shale gas developed in these formations.
Rock mechanics tests on core from Early Cretaceous carbonate reservoirs from a super-giant field offshore Abu Dhabi has allowed definition of rock mechanical facies (RMF). Each of four RMF are based on stress-strain curves and associated strength and elastic parameters. The lab-based RMF correlate with mechanical stratigraphy classes previously defined from core (and that reflect visible differences in lithology and cementation). The RMF are correlated to reservoir zones and inter-reservoir, impermeable dense intervals, with three facies predominantly correlating with reservoir lithologies and one corresponding with primarily dense intervals. However, some reservoir zones, or sub-zones, can lie in more than one RMF. The RMF are, therefore, partly predictable: for any reservoir zone in the field prediction accuracy is to one or one of two RMF classes. This ambiguity is due to two factors: (i) lateral variation of RMF within some reservoir zones based on lithofacies; and (ii) continuity of mechanical properties between RMF classes. There is a change in RMF from crest to flank of the reservoir, as expected, but there is also local lateral variation within the crest of the field. The two RMF representing most of the reservoirs are expected to respond differently to field operations. Therefore, mapping lateral variation of RMF for some reservoir zones may provide a basis for implementing different reservoir management practices in different areas/zones of the field. The ultimate use of this information will be to enable full-field rock mechanics simulation of the reservoir to help understand the long-term effects of different production strategies.
Introduction & Background
The concept of mechanical stratigraphy is widely used, commonly to correlate fracture distribution and intensity to stratigraphy. The concept of rock mechanical facies (RMF) whereby a number of measured rock mechanical properties are correlated to stratigraphy is not new and is referred to in a number of papers, for example: Alhilali & Shanmugam (1991); Corbett & Friedman (1987); Yale & Jamieson (1994); McDermott et al., (2006); Khaksar, et al. (2009). However, RMF do not seem to be commonly used as a concept. We believe that characterising formations in terms of RMF has the potential to simplify characterisation for use for drilling; reservoir management; and history matching for simulation. In this paper we will describe how we have defined RMF for an oil-field and will discuss one way in which RMF could be used in the field.
The studied oil-field comprises a stack of limestone reservoirs separated by impermeable "dense?? limestone layers of Early Cretaceous age in a giant field located offshore Abu Dhabi (Figures 1 & 2). Production in the field has been by variably patterned water-flood over the last 30+ years. The dense layers measure up to a few tens of feet in thickness; the main reservoirs are up to 150 ft. The reservoirs are typically characterized by moderate to low matrix permeability, generally, but not exclusively, from 50 mD to 2 mD. Porosity is mostly in the range of 15-25%, more than half of which is microporosity. Depositional textures are predominatly wacke- to packstone with high-permeability streaks due to rudist and algal floatstone to rudstone and grainstones. Although intense bioturbation has destroyed most of the depositional textures, heterogeneities remain in some reservoirs in the form of dolomite-filled burrows, patchy/nodular cementation, stylolites and wispy solution seams, and fractures; all can occur as different layers within the reservoir. The reservoirs are not highly fractured although diffuse fractures are concentrated at the top and base of most reservoirs.