Najmah-Sargelu Formations of Kuwait show considerable potential as a new unconventional hydrocarbon play and produces mainly from fractures. The key uncertainties which affect the productivity are the nature and distribution of permeable fracture networks, and the limits of oil accumulation.
This paper presents the results from whole-rock elemental analysis of three cored wells in UG field. The main objectives of this study are to use high-resolution elemental chemostratigraphy to gain a better understanding of the detailed stratigraphy and correlation of the Najmah-Sargelu Formations, to assess the chemo-sedimentology for determining the intervals of high organic content, to estimate the mineralogy of the sequence using an algorithm developed for an analog formation in North America; and to determine the most likely intervals to contain fractures, using a brittleness algorithm.
A clear chemo stratigraphic zonation is recognized within the Najmah-Sargelu Formation. The larger divisions are driven mainly by inherent lithological variation. The finer divisions are delineated by more subtle chemo stratigraphic signals (K2O/Th and Rb/Al2O3 ratios) and preservation of organic matter (high V, Ni, Mo, and U abundances). Zones of alternating brittleness and ductility are clearly identified within the interbedded limestones and marlstones of Najmah-Sargelu Formation.
Two unexpected but important features of the Najmah-Sargelu limestones were elucidated by the elemental data. Brittle, high-silica spiculites, with virtually no clay or silt, are more common than previously recognized from petrophysical logs and core descriptions in the upper Najmah limestones. In addition, the limestones adjacent to the spiculites tend to contain bitumen as pore-filling are recognized by the trace metal proxies. Ternary plots of V, Ni, and Mo differentiate the combinations of kerogen and bitumen present in the Najmah-Sargelu Formations.
The clarity and sensitivity of the chemostratigraphic signals are sufficient to enhance formation evaluation, and can also assist borehole positioning using the RockWiseSM ED-XRF instrument at wellsite.
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.
Whole level of the erosion and the resistance of rocks which were composed closured have been studied, besides, the impact of temperature and laser irradiation for more investigation about this issue has been involved before all. This subject more reveals the matter which laser absorption on the laboratory scale using laser to what extent can cause the augment of the relative permeability and secondary porosity of reservoir rock, that of the vertical and horizontal useful connectivity and eventually that of the positive transferability.
This research has been carried out in the form of case study on one of Iranian south west formations in north east of Behbahan city in Iran, either the rate or generation of forming the subtle and large fractures has been studied by considering and preparing this section from rocks of stratified sequence of the laboratory area before and after the laser irradiation operation and various analyzer by the means of Spectrophotometer and advanced electron microscope. It should be noted that during the erosion and ablation in the laser drilling operation in the experimental rocks of considered field, given the capability of the field, the formation and field lithology we observed the creation of fractures at the level of micro and nano simultaneously whose vacant spaces were positive, and reservoir and some others were neutral, this fractures can be created by the rate of crude oil absorption. The main purpose of this study is to advance the operations towards the higher technology in order to the better efficiency in the field of the well completion to be gained improving the rate of oil production by the introduction of this modern method of improving and fracturing reservoir which uses certain specialized parameters and indicators, and, finally, the certain method that might be a better way to use laser irradiation on our chosen formation of Iran.
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.
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.
This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 156240, "A New Model of Bit Whirl," by Yevhen Kovalyshen, CSIRO Earth Science and Resource Engineering, prepared for the 2012 SPE/IADC Asia Pacific Drilling Technology Conference and Exhibition, Tianjin, China, 9-11 July. The paper has not been peer reviewed.
The Barremo-Aptian Urgonian formation is widespread in southeastern France. This formation is a giant (20 000 km²) limestone platform deposited along the northern Tethyan margin during the lower Cretaceous, on the Vocontian basin margin. The Urgonian carbonates are mostly composed of rudist facies interupted by several Orbitolinids-rich level. This formation has an equivalent in time in the Middle-East series: the Kharaib, Hawar and the very beginning of the Shu'aiba formations. The quality and diversity of Urgonian outcrops in southeastern France lead that formation to be a good reference proxy of Middle-East reservoirs and to be used for the assessment of sedimentary internal architecture.
A work program focused on the appraisal of geometrical and petrophysical heterogeneity in Urgonian has integrated the acquisition of multi-scales static and dynamic data: outcrop studies (facies, fractures, microfauna …), well drilling, well tests, aerial photographs, springs and aquifer survey. A huge database has been constituted, it comprises several key sections and more than 60 vertical wells drilled in the Urgonian aquifer, 40 well tests and survey of 13 springs during one year.
Three sequences have been described in the Upper Barremian (Ba3, Ba4 and Ba5) and two sequences in the Lower Aptian (A1 and A2). The existing biostratigraphic chart built for several years by Annie Arnaud-Vanneau for the northern region (Vercors) has been improved and completed including the new data from the western zone (Gard and Ardèche).
Through a multidisciplinary approach integrating sedimentology, hydrogeology and structural geology, a new conceptual model for the architecture of the Urgonian deposits on the edge of the platform is proposed. In the study area, three N110° normal faults subdivide the domain into four tilted blocks. The differential subsidence related to this faults activity makes important variations in thickness and facies distribution according to the location in the blocks.
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.