Dakshinamurthy, Natarajan (Kuwait Oil Co.) | Verma, Naveen Kumar (Kuwait Oil Co.) | Abdul Salam, Tareq (Kuwait Oil Co.) | Al-Sammak, Ibrahim (Kuwait Oil Co.) | Koronfol, Safouh (Ingrain Inc.) | Dernaika, Moustafa (Ingrain Inc.) | Teh, W J (Ingrain Inc.)
Digital Rock Physics (DRP) has significantly evolved in the last few years and added invaluable contributions in improving core characterization and in providing high quality advanced SCAL measurements, emphasized through various studies (Al Mansoori et al., 2014 and Kalam et al., 2011).
This paper represents a unique DRP relative permeability SCAL study done on two plug samples from a carbonate reservoir in the Middle East. It outlines the DRP method used to determine the relative permeability curves including sub-sample selection, high resolution CT scanning (down to nano level), generation of the 3D rock models, and simulation of fluid flow displacements.
The paper will also discuss the power of pore scale imaging and how it helps in understanding macro property variations. The DRP results are comparable to the SCAL results of same formation of nearby fields and are currently being used for the Full Field simulation. The conclusions will be supported by a comparison with physical lab measurements that were done independently on samples of the same formation from the same well’s core.
Such comparison will demonstrate the added value in using DRP, and will show the effectiveness of the technology in generating advanced SCAL data in a significantly shorter timeframe compared to conventional laboratory measurements.
Relative permeability (Kr) curves provide macroscopic description of the way in which two (or three) phases flow together locally in a porous medium (Honarpour et al., 1986 and 1995; Heaviside, 1991). Imbibition water-oil Kr data are critical in the evaluation and management of fields having natural water influx or having planned or actual water-flooding. However, high percentage of such laboratory measurements yields unrepresentative data that cannot be used in reservoir simulation models or as input for history matching of production profiles. In addition, the traditional laboratory evaluation methods may not be applicable to every testing condition or every type of reservoir rock and hence the continued development of laboratory methods is required to help characterize and understand challenging reservoir behaviors (Dernaika, 2010 and Serag et al., 2010).
Digital imaging technology has been extensively used in the petroleum industry to obtain fast and reliable core data from reservoir rock samples. The technology (Digital Rock Physics) has contributed reliably to reservoir core characterization through the application of Dual Energy X-ray CT Scanning (Walls and Armbruster, 2012 and Al-Owihan et al., 2014) and to the prediction of reservoir engineering quantities like capillary pressure and relative permeability through direct simulation into high resolution 3D images (Amabeoku et al., 2013, De Prisco et al., 2012, Mu et al., 2012 and Grader et al., 2010)
The Marrat reservoir in Dharif field is a deep, sour, high pressure oil accumulation of Jurassic age containing light under-saturated oil of 36-380 API. The carbonate reservoir has a porosity range of 10-20% with permeability of 1-10 md. The field was put on production in 1989 through one well. Subsequently, 10 wells were added gradually developing the field. As of date, the field has produced about 12.5% of oil in place, lowering the reservoir pressure from 10,525 to 7,000 psi.
At present, oil production from the field is about 13,500 bbls/day. Due to low permeability, some wells produce with high drawdown approaching asphaltene onset pressure (AOP), estimated at 3,400 psi. This causes Asphaltene deposition in the tubing that requires cleaning to maintain the production level. The major challenges now are to produce the wells above AOP to avoid asphaltene precipitation in the wells or reservoir while sustaining the production level and maximizing recovery.
Hence, Full Field Model (FFM) for simulation studies was constructed and history-matched. Under depletion case, where the wells produce above AOP, field produced about 24% STOIIP. The water injection case shows significant increase in recovery to 40% STOIIP. Since no prior experience of water injection is available for such tight deep carbonate reservoirs in West Kuwait Fields, several key studies such as a) RCAL & SCAL b) Core flood Study c) Water Compatibility & Scale Prediction modeling d) Injectivity test, were carried out to address water injection feasibility.
The present paper shares the results of above studies which indicate that water injection is a viable option to maintain the reservoir pressure to produce the wells above AOP as well as to maximize recovery. Pilot water injection is planned through one well for which the area has been optimized using FFM. At present Pilot Water injector and source wells have been drilled and injection will be initiated with commissioning of surface facilities
Dharif field is NNE trending elongated anticlinal structure with faulted western limb. The Marrat reservoir in this field has developed in carbonate aggradational and progradational depositional setting. The field was discovered in 1988, put on production in 1989 and gradually developed with additional producers until 2004 (Fig-1). As of today, total 13 deep wells have been drilled in this field of which eleven are completed in the Marrat reservoir, while two are completed in a shallower Jurassic reservoir. The reservoir porosity ranges between 10-20 % while the average permeability is low, ranging between of 1-10 md with locally higher permeability of about 20 - 30 md in some layers. The average net reservoir thickness is about 200 ft and water saturation is less than 15 %. Initial oil water contact (OWC) was estimated to be 13,360 ft Subsea. The initial reservoir pressure was 10,525 psi at 13,200 ft SS (datum). The oil is under saturated with saturation pressure as 1,959 psi. Oil is light and the density is 36-380 API. The asphaltene onset pressure (AOP) is nearer to 3,400 psi, at a temperature of 2350 F.
Verma, Naveen Kumar (Kuwait Oil Company) | Al-Medhadi, Fahed (Kuwait Oil Company) | Al Shamali, Adnan Aiesh (Kuwait Oil Company) | Dakshinamurthy, Natarajan (Kuwait Oil Company) | Matar, Saad Awad (Kuwait Oil Company) | Reji, E.C. (Kuwait Oil Co.)
Najmah-Sargelu (NJ-SR) unconventional fractured carbonate and Middle Marrat (MMR) tight carbonate Jurassic reservoirs are spread across many fields in West Kuwait where new Jurassic oilfields are still being discovered. Oil is being produced since late eighties mainly from MN, UG, AB and DF structures. Drilling through over pressured and fractured NJ-SR reservoir, lying below thick high pressure Gotnia Evaporites is challenging due to well control issues such as total mud losses and kicks compounded with high H2S- high CO2 corrosive environment. Moreover, pressure reversal in MMR and depleted pressures pose further complications resulting in costly wells. A total of 53 wells drilled in these fields until 2002, were all vertical (Fig.1) except one NJ-SR high angle well drilled in year 2000 which could not be tested due to complications during completion. Although many wells produced at high rates of 5000-10000 bopd, some failed to produce for their inability to intersect productive fractures in NJ-SR or due to low PI in tight MMR carbonates.
This paper presents an overview of recent efforts in planning and drilling unconventional wells addressing cost-effective development of multiple Jurassic reservoirs. First such well in 2003 was a long reach horizontal well that was successfully tested and produced from NJ-SR. This was followed by Kuwait's first long reach medium radius re-entry horizontal well in 2004 that was tested and completed open-hole in MMR successfully. A 1100ft lateral drain-hole for productivity enhancement in MMR was geosteered successfully on planned trajectory in 2006 through re-entry. The well showed oil indication during initial testing; however, it was suspended due to post-stimulation complications during testing. Recently, the first deviated development well was drilled and completed where the trajectory was optimized for both NJ-SR and MMR reservoirs. The well successfully intersected planned fracture-swarm in NJ-SR where core was acquired and oriented to characterize the fracture zone. Other complex wells include vertical deepening for transferring water producing NJ-SR well to MMR extending productive life of non-usable well. Well planning for a complex NJ-SR deviated - MMR horizontal well was completed early this year and drilling is expected to be finished in 2007 followed by a long reach NJ-SR re-entry horizontal sidetrack besides the first MMR water injector in 2008.
These unconventional complex wells have successfully met technical challenges in planning & drilling while addressing productivity enhancement and cost-effective development of multiple Jurassic reservoirs. Learning gained in these wells will go a long way in finalizing cost-effective field development plans incorporating optimal well trajectory, completion designs and off take strategies for maximizing recoveries from these difficult and challenging reservoirs.
Unconventional fractured Najmah-Sargelu and tight Middle Marrat carbonates constitute Jurassic reservoirs in West Kuwait. Appraisal and development of these deep reservoirs spread over several oil-fields containing light but sour crude, is a challenging task that often requires unconventional ‘out-of-box' thinking, and unique well designs with improvised work-flows & methodologies. Several first time applications of new industry trends and cutting-edge oilfield tools and techniques have been employed to address these challenges. This paper describes as to how some of these challenges have been met through integrated multidisciplinary teamwork leveraging latest industry trends, tools and techniques.
The oil accumulations in NJ/SR reservoirs are formed as a result of unique geology characterized by organic rich mature source rock interlayered with tight fractured carbonate rocks. These are deep, over pressured reservoirs are sealed at the top by a thick Gotnia Salt-Anhydrite cap-rock, and is underlained by Dharuma shale below. The productivity of this low matrix porosity reservoir (<5%) is enhanced by the occurrence of natural fractures created as a consequence of folding and faulting, some of which remained open through a combination oil recharge, and high reservoir pressures coupled with horizontal stress anisotropy.
Verma, Naveen Kumar (Kuwait Oil Company) | Al-Medhadi, Fahed (Kuwait Oil Company) | Franquet, Javier Alejandro (Baker Hughes Inc) | Maddock, Robert Huw (Baker Atlas) | Dakshinamurthy, Natarajan (Kuwait Oil Company) | AL-Mayyas, Eman Abdullah (Kuwait Oil Company)
This paper presents the methodology to identify critically stressed fractures, CSF, in naturally fractured reservoirs. A natural fracture is considered to be critically stressed if the ratio of shear and normal stresses acting on the fracture surface exceeds the frictional strength of the reservoir rock. The main objective is to identify the critically stressed fracture trends in the reservoirs in order to design wellbore trajectories that efficiently intersect theses fracture trends. In addition, geomechanical analysis for drilling scenarios under depleting reservoir conditions addressing well-bore stability is attempted to formulate drilling and completion strategy.
Critically stressed fracture identification has several important implications on fluid flow behavior through naturally fractured porous media. It has been shown that fluid flow in fractured rocks is largely controlled by critically stressed fractures; therefore, critically stressed fracture analysis may enable to systematically identify producing fractures in the reservoirs that mainly produce through natural fractures.
The CSF analysis includes the mechanical property characterization of the formations and the in-situ stress tensor description acting on the reservoirs. The fracture orientations from core description & borehole image log interpretation were used for the CSF analysis because fracture dip and strike are needed for the stress calculation on fracture planes. This analysis is particularly useful where several fracture trends are identified in a reservoir, with some trends more likely to be open and productive due to horizontal stress anisotropy. The case history illustrates application of CSF Analysis in conjunction with geomechanical wellbore stability analysis in selection of optimal well trajectory and formulation of drilling and completion strategy for producing a naturally fractured carbonate reservoir.