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.
The Large Scale Steamflood Pilot (LSP) is a project aimed to determine the feasibility of economically steamflooding the Wafra First Eocene carbonate reservoir. The field is located in the Partitioned Neutral Zone, between Kuwait and Saudi Arabia. The reservoir is a dolomite, with 14-20*API oil. The LSP consists of sixteen inverted 5-spot injection patterns. A fully integrated workflow was matured to maximize the value of information provided by four full cores that were collected when drilling the LSP wells. Core work will support reservoir characterization and dynamic simulation, essential tools for project decision-making. High-level workflow consisted of the following phases: (i) define field, laboratory and office activities, (ii) identify and prioritize stakeholders, (iii) delineate project schedule and assign responsibilities. Coring and core
analysis for heavy oil involves short, mid and long term activities, that may require several years of planning and execution. Planning and frequent communication engaged core experts very early in the work process. Their input was used to shape the project, assuring reliable execution of dependent and independent tasks as work progressed. Synergies between subject matter experts were promoted, and proved to add value to the project. Due to the organizational efforts, the project schedule was not affected by personnel changes. Concerning lab measurements, the operator's heavy oil experts recommend Best Practices for the determination of relative permeability. Long equilibrium times, crude oil instabilities, and viscous fingering are challenges unique to heavy oil systems. Limited capability for such measurements exists in the industry. Heavy oil tests are not routine and should be carefully assessed. We hope that the integrated workflow proposed in this paper provides guidance to similar projects on planning and execution of heavy oil coring programs and analysis.
The Large Scale Steamflood Pilot (LSP) is the third in a series of staged tests conducted to validate the feasibility of applying the enhanced oil recovery technology of steamflooding to unlock the production potential of the heavy oil Eocene reservoir in the onshore Partitioned Neutral Zone (PNZ). Refer to Fig. 1 for the PNZ location. Previous tests included the Small Scale Steamflood Test (SST), which was successfully completed in 2008, and simple steam stimulation testing, conducted in the
late 1990s. The LSP consists of sixteen inverted 5-spot injection patterns. The project is expected to lead to full-field steamflooding of the First Eocene reservoir, marking the first commercial application of a conventional steamflood in a carbonate reservoir anywhere in the world.
The First Eocene is the shallowest reservoir at Wafra field. Average depth to the top of the reservoir is about 1,000 feet. The stratigraphic interval averages 750 feet thick with a gross average porosity of 35% based on well log and core data, and a gross average permeability of 250 md based on core plug measurements. Based on current field practice a porosity cutoff of 35% is used to define net reservoir. The average porosity in the net reservoir is 43% and the net average permeability is about 280 md. The reservoir was discovered in 1954. Full field development and production commenced in 1956. Current oil cumulative from the reservoir is over 300 MMBO. Oil production exceeds 25,000 BOPD of 14-20 ºAPI high-sulfur oil. The First Eocene is a depletion drive reservoir, with partial solution gas drive and limited aquifer support. The aquifer support is not sufficient to maintain the reservoir pressure at current production rate.
A fully integrated workflow was matured to maximize the value of information provided by four LSP cored wells. Core work will support reservoir characterization and dynamic simulation, essential tools for project decision-making. The purpose of this paper is to describe the approach that was followed to maximize the value of heavy oil core analysis and support the LSP development with appropriate petrophysical data.
Lower Burgan, a giant clastic reservoir in Sabiriyah field of North Kuwait was discovered during mid 50s ( Location map shown in Figure-1). An integrated performance analysis recently carried out indicated that the reservoir has a much higher potential than anticipated earlier. Though the cumulative recovery till date was more than 70% of the initial recoverable reserves, the reservoir pressure decline was insignificant with average water cut of about 20% only in this active water drive reservoir. Significant additional open hole data in new well penetrations, cased hole log data, seismic re-interpretation, additional production performance and pressure data acquired since last major reservoir update in 1998, has considerably improved the reservoir potential understanding of Lower Burgan.
Although reservoir performance suggested possibility of larger STOIIP base, lack of sufficient mapped net pay area impacted the deterministic STOIIP estimation negatively in the past. The additional information obtained in the new wells has opened up a large additional pay area by way of structural refinement, lowering of OOWC and additional net sands mostly in L-member. Whilst number of wells drilled in southwest flank and in north and south indicated possible occurrence of a deeper OOWC than earlier interpretations, SA-X1, the well drilled and tested beyond the reservoir limit in southern area, produced dry oil from sands with high Sw.
In order to assess the full potential of new reservoir area and to test the mobility of oil below the hitherto OOWC, a detailed testing program was formulated and implemented. MDT sampling was undertaken at several wells with successful results to prove the mobility of oil. Rigless perforation/ testing job were done at one of the identified wells, showing only traces of oil. Cores were cut with full suite of open hole logs and the RFT data. Production testing at newly completed wells, long term build up tests, PLT data and RST logs confirmed the additional potential for this mature reservoir, which was supposed to be on decline as per earlier predictions.
The paper is a classic example as to how a mature reservoir has been re-assessed and brought to the development limelight in terms of enhanced STOIIP, Reserves and production.
The Lower Burgan comprises a broadly transgressive succession of paralic clastic- sediments. Fluvial processes dominate in the lower part of the formation; influences from marine processes became stronger upwards. Higher frequency changes in sea level become more important in the upper part of the formation, making this part of the reservoir more complex.The reservoir architecture was defined by the depositional processes, which were mostly channel processes. The internal make-up of these channels depended on the relative degree of marine influence, and they range from fully fluvial channels, through deltaic channels, tidally influenced channels, and more marine estuarine channel fills.
Sequence Stratigraphy is used as main basis for layering scheme of this reservoir. The key correlatable surfaces that mark significant landward or basinward shifts are identified on the basis of core study and distinctive characteristics on wireline logs. Based on the above Lower Burgan was divided into six layers-LB25, 50,55,70,80 & 100 (Badely Ashton). Later on it was felt that the Badley Ashton layering was not sufficient to define flow property of the reservoir. Therefore, based on reservoir pressure and flow behavior, the lower Burgan reservoir has been divided into as many as thirteen layers /flow units. It includes the key stratigraphic surfaces identified by Badley Ashton, together with some additional intermediate surfaces, which were later found, by Badley Ashton, not to have stratigraphic significance. Figure 2 compares the new , and Badley Ashton correlation schemes, and relates them to the traditional division of the Lower Burgan into a massive lower sand unit, called the M member, and an upper interbedded unit of sands and shales, called the L member. The boundary between L and M varies from well to well and cuts across the stratigraphy.
Comparison of petrophysical properties between Eastern U.S. Silurian-age sandstones and Western U.S. Cretaceous-age sandstones illustrates the universality of certain low-permeability reservoir properties. In the Medina insitu porosities are generally within 97% of routine porosities and in Mesaverde-Frontier are approximately 0.8 porosity percent less than routine porosities. In both groups insitu Klinkenberg permeability (ki) exhibits an increasing difference from routine air permeability with decreasing permeability. Both groups of low-permeability sandstones exhibit very similar decrease in "irreducible" water saturation (Siw) with increasing ki. However, lithologic variations that are related primarily to grain size and shaliness cause variance in Siw at any given permeability. Both eastern and western low-permeability sandstones exhibit sharp decrease in gas relative permeability ( krg,Siw) with increasing Siw. The krg,Siw values are generally less than 5% at Siw greater than 60%. Although average krg,Siw is low and average Siw is high, these sandstones typically produce water-free gas. Analysis of cumulative flow capacity in wells in both regions indicates that a significant fraction of total flow capacity often comes from a few, thin, higher permeability intervals within generally low-permeability sandstone. Although storage capacity declines with decreasing permeability due to increasing Siw, low-permeability intervals still represent a significant fraction of total storage.
Lower Silurian-age low-permeability Medina Group (Medina) sandstones of the Appalachian Basin and Upper Cretaceous-age Mesaverde Group (Mesaverde) and Frontier Formation (Frontier) sandstones in several Western U.S. basins are important targets for natural gas exploration and production. Recoverable reserves are estimated to be approximately 30 trillion cubic feet (TCF) in the Medina1 and approximately 10 TCF in the low-permeability Mesaverde and Frontier.2 The abundant gas reserves of the Medina, which drillers locally call the "Clinton," are regionally extensive and without a recognized downdip water contact. Mesaverde and Frontier reservoirs exhibit similar undefinable gas-water contacts. In both areas water can occur updip of gas production.
Prediction of gas producibility from low-permeability sandstones is complicated because conventional log-analysis interpretation and formation-evaluation parameters are commonly not applicable. Furthermore, conventional core-analysis petrophysical values can differ significantly from reservoir values. Early work on petrophysical properties of low-permeability sandstones demonstrated that pore-volume compressibility is small and that increasing confining stress and water saturation cause permeability to decrease.3,4,5 Jones and Owens6 quantified these effects and concluded that the presence of a thin, sheet-like, tabular pore structure could explain the response to confining stress. Ostensen7 provided a comprehensive theoretical analysis of the relationship between grain boundary micro-crack dimensions and permeability. Dutton et al.2 summarized the properties of low-permeability sandstones in the U.S. and provided extensive references to previous studies. Recently, Byrnes 8 summarized insitu rock properties for low-permeability sandstones in Rocky Mountain basins and Castle and Byrnes9 presented insitu rock properties for the Medina in northwestern Pennsylvania.
Laboratory displacement measurements and compute simulations were performed to support field evaluations of residual oil saturation for a high permeability sandstone reservoir exhibiting moderate permeability sandstone reservoir exhibiting moderate to weakly water-wet characteristics. Logging a sponge core data had indicated low oil saturations in zones depleted by natural bottom water drive. The laboratory displacement tests were designed to help further verify these results and to provide data most applicable for the prediction of future field performance. Reservoir conditions displacement test data were in reasonable agreement with the field results, but laboratory conditions tests predicted higher residual oil saturations. Water predicted higher residual oil saturations. Water flood and centrifuge measurements were in agree under appropriate experimental conditions.
Simple simulations were conducted to evaluate factors affecting the gravity drive process during vertical displacement of oil by water. Particular attention was paid to sensitivity analyses of the effects of the oil relative permeability and viscosity characteristics. The results obtained are useful for reservoir management questions relating to production rates, coning phenomena, and time-lapse monitoring of saturation changes.
Effective reservoir management requires the integration of information from a variety of sources. Geological and engineering models are ideally used as dynamic tools, to be revised and upgraded as needed to account for the most recent field performance. Likewise, laboratory-derived data on performance. Likewise, laboratory-derived data on rock, fluid, and fluid flow properties are subject to review and verification based on observed reservoir production characteristics.
This paper describes a laboratory test program in support of field evaluations of residual oil saturation for a high permeability sandstone reservoir in the Middle East that produces by natural water drive. The laboratory work was initiated to resolve previously-observed differences in oil displacement efficiency from centrifuge and waterflood tests on the reservoir rock. The present work also provided a better definition of present work also provided a better definition of core sample handling and testing methods most applicable for use in the prediction of field performance. A second phase of the study involved performance. A second phase of the study involved some simple simulations to evaluate factors affecting the efficiency of the gravity drive mechanism during vertical displacement of oil by water.
FIELD DETERMINATIONS OF RESIDUAL OIL SATURATION
Sponge coring and extensive logging in one well indicated that the residual oil saturation averaged only about 14% in a continuous sand section depleted by bottom water drive. The naturally depleted water-swept interval in this well extended 30 feet above the original oil-water contact.
The well was drilled using a water-base bland mud formulation having an API filtrate loss of less than 8 cc. The friable, poorly-consolidated nature of the reservoir rock caused low core recovery over the swept zone (about 7 ft. out of 28 ft. cut), in contrast to good overall recoveries achieved in other wells using more conventional plastic sleeve core barrels. It was nevertheless possible to process ten, 3 1/4" diameter whole core samples and process ten, 3 1/4" diameter whole core samples and the associated sponge from the swept zone. Table 1 gives a summary of the results. The average oil saturation was determined to be 14% at reservoir conditions, in good agreement with a range of 12-17% measured by different logs and a single well tracer test.