The Middle cretaceous Wara sandstone reservoir in Minagish Field is considered as highly heterogenetic sandstone which implying lateral facies extensive variations, stacked sand bodies with varying petrophysical properties. Several horizontal wells has been successfully drilled in lower part of Wara 6 sand channel, best thicker clean sand channel with very good oil production rate. Recently some wells have shown depleting of oil and increase water production. To develop such a challenging reservoir to maximize the oil production, a new plan has been developed to explore for new opportunities in Wara reservoir. The objective is to target different good stacked sand bodies in different Wara layers by drilling deviated wells. Some of old depleted Minagsih Oolite reservoir wells have shown good opportunities to sidetrack the wells into good Wara sand layers. This paper presents the integration between geostatistical models, well logs, well test results and different seismic elastic properties maps to identify best subsurface locations for drilling new deviated wells which combine the best quality sand bodies in different Wara layers. A few years ago geostatistical reservoir model along with core data and well log data were utilized to drill successful horizontal wells in W6 sand channels. However due to low resolution seismic data, Wara highly heterogonous lithology and uncertainty in geo-statistical model, it was challenging to continue identify good quality stacked sand bodies in different Wara layers without drilling unwanted silty sand or shale layers. Seismic inversion related elastic impedance data could discriminate between the good quality oil-bearing sand, shaly, and silty sandstones. Several old vertical wells that include good stacked sand bodies in different Wara layers; have been selected to validate the accuracy of elastic impedance maps along Wara layers.
Green fields today mostly can be regarded as marginal fields and successfully developed. It covers the complete assessment of the oil and gas recovery potential from reservoir structure and formation evaluation, oil and gas reserve mapping, their uncertainties and risks management, feasible reservoir fluid depletion approaches, and to the construction of integrated production systems for cost effective development of the green fields. Depth conversion of time interpretations is a basic skill set for interpreters. There is no single methodology that is optimal for all cases. Next, appropriate depth methods will be presented. Depth imaging should be considered an integral component of interpretation. If the results derived from depth imaging are intended to mitigate risk, the interpreter must actively guide the process.
Gorgi, Sam (Halliburton) | Joya, Jose Francisco (Halliburton) | Al-Ebrahim, Ahmed (Kuwait Oil Company) | Rashed Al-Othman, Mohamad (Kuwait Oil Company) | Abdullah Al-Dousari, Mohamad (Kuwait Oil Company) | Mohamad Ahmed, Abdulsamad (Kuwait Oil Company) | Omar Hassan, Mohamad (Kuwait Oil Company) | Mohammad Al-Mansour, Jassim (Kuwait Oil Company) | Elsayed, Abdou (Kuwait Oil Company) | Alboueshi, Alaa Eldin (Halliburton) | Allam, Ahmed (Halliburton) | Robles, Fernando (Halliburton)
This paper presents a case history application of real-time fiber-optic technology in the Bahrah oil field, onshore Kuwait. A primary challenge during openhole swellable packer completion operations with multistage fracturing is understanding the number of fractures induced in the formation, particularly in heterogeneous formations where the fracture pressure energy will be distributed along the openhole section. Therefore, fiber-optic technology was selected for the Bahrah project. The application consists in diagnosing a tight carbonate reservoir after multistage acid fracturing and milling the baffles of a production sleeve completion to obtain a well production profile. This technology consists of a fiber-optic cable and a modular sensing bottomhole assembly (BHA). The fiber-optic cable provides distributed temperature sensing (DTS), whereas the BHA is used to monitor pressure, temperature, and the casing collar locator (CCL) in real time.
The usual procedure when using conventional coiled tubing (CT) to stimulate a carbonate openhole section is to treat all pay zones with acid and diverter, which increases both operation time and operational costs. In addition, inadequate control of the treatment placement will often result in ineffective stimulation. When using the fiber-optic technology, monitoring is performed by analyzing the distributed temperature profiles both before and after stimulation; the BHA helps ensure that the optimum pressure is maintained and that the fluid is placed accurately through depth correlation sensors. All components of this intervention are performed in a single trip, which reduces both costs and operation time.
This paper presents an application that uses the modular sensing BHA to improve the performance of milling balls and baffles in the horizontal production sleeve completion. Afterward, DTS is used to diagnose the reservoir performance after multistage acid fracturing to identify fracture initiation points (FIPs). This assists in design optimization, provides better understanding of formation properties, and helps determine the flow rate distribution of each stage across the entire lateral. Another application uses DTS to obtain the production profile of a 3,286-ft horizontal section while flowing back the well through an electrical submersible pump (ESP). The paper presents the methodology and results of these applications.
Using this technology in the petroleum industry helps reduce operation time by up to 50% as a result of performing various CT activities in a single run. This eliminates the need for additional logging or slickline runs using the same BHA, after performing the milling operation to collect DTS data for FIPs and flow rate distribution analysis in the same run. It also reduces costs by enabling real-time decision-making capabilities and effective stimulation.
A powerful new tool for unconformity identification in a range of geological environments is presented together with very strong evidence of its utility.
Commonly in an exploration setting correct sequence interpretation has taken years and multiple detailed studies, now with the new tool it can be done quite easily in near real time.
Recognition of unconformities in boreholes, particularly where correlation with outcrop is not available, traditionally relies on paleontological methods, normally palynology or micropalaeontology and correlations between wells where sections of the observed sequence are missing. Observations in recently drilled wells in Dubai have provided evidence for another useful tool.
While drilling Well A, bulk rock phosphate concentrations were obtained in near real time while drilling using X-ray fluorescence (XRF). These were then plotted against well depth. Phosphate values were taken as indicators of long duration and high intensity of organic production or conversely a low rate of sedimentation. Unconformities were marked by significant and obvious phosphate peaks while drilling in a marine sequence. Higher than average concentration of phosphates in marine environments during periods of non-deposition or very slow deposition have been known for some time but their use as markers for unconformities while drilling has not been widespread due to the practical difficulties with sample analysis. With advances in XRF technology routine wellsite XRF analysis services are now available.
Plots of phosphate concentrations in Well B which was drilled through a sub-aerially deposited sequence also showed phosphate peaks, some of which correlated with known and recognisable unconformity surfaces. Further evaluation, particularly comparison with palynology data, showed that the phosphate peaks which did not correlate with known unconformities indicated previously unrecognised unconformities. Phosphate peaks on unconformity surfaces in sub-aerially deposited sequences have not, as far as the authors can determine, been previously recognised.
Well C is an older well which penetrated a similar sub-aerially deposited sequence to Well B with no XRD analyses available. Correct interpretation of the Well C sequence was not possible until the key points were derived from the more complete Well B data.
Evidence is presented showing that phosphate peaks are practical and useful indicators of unconformities in near real time, especially when interpreted with other geological information. An example is also given of an unconformity which displays no phosphate peak together with an explanation as to why there is no peak.
In an exploration setting analysis of phosphate trends can significantly enhance and simplify sequence and palaeoenvironmental interpretation and understanding of regional tectonics thus providing greater insight when planning follow up wells leading to a higher success rate. As such it is a new and novel exploration tool with a potentially high economic value.
The sandstone facies of Wara formation designated as Ac zone in the Bahrain Field belongs to the Wasia group of the Middle Cretaceous age.
The reservoir has been characterized in three distinct geographical areas of sand distribution based on varied depositional systems, resulting in sands with differing orientation, texture and thickness. The reservoir varies in thickness between 5 and 60 ft and is composed of a series of discontinuous high porosity, high permeability sandstone lenses, sealed above and below by thick competent marine shales.
This paper addresses the variability of the reservoir and the connectivity with the underlying Mauddud reservoir which consequently determined the drive mechanisms.
The original oil in place of Wara sandstone was calculated deterministically using a 3D geological model and incorporated both Geophysical and Petrophysical models. Initial water saturation was calculated from capillary pressure data with net sand cut offs applied. The discontinuity of the sands has resulted in individual sand bodies with variable oil water contacts. Thinner sand bars and channels in the northern area of the Bahrain Field produce by depletion drive. Juxtaposition with the underlying Mauddud reservoir occurring across the faults allows communication with Mauddud gas cap in the Central area which results in the gas drive. Water drive is the main mechanism in the South channel.
Recent log data acquired from new wells has improved our knowledge of this reservoir and explains the different oil-water contacts with the varying drive mechanisms. This improved understanding has resulted in a new development strategy to maximize recovery with infill drilling and possibly Enhanced Oil Recovery (EOR).
The Bahrain Field, being the first oil discovery in the gulf region in 1932, is now in a mature stage of development. Crestal gas injection in the Mauddud reservoir has continued to be the strongest driving mechanism since 1938. Over the last five years, gas injection and fluid production rates have grown three folds with expanded drilling, workovers, and high volume lift activities. However, there are significant opportunities to increase oil production and optimize gas injection.
An Immiscible-Water-Alternating-Gas injection (IWAG) process was carried out on two composite samples extracted from the Mauddud reservoir of the Bahrain Field. The resulting production and pressure profiles were history matched by using hysteresis and three-phase relative permeability modeling options. Representative relative permeability and capillary pressure curves with the associated hysteresis and three- phase relative permeability parameters were obtained by history matching the experimental IWAG flood results. The history match was carried out by generating the hysteresis parameters and relative permeability curve sets. Experimental results, including two-phase water/gas flood steady state and unsteady state results, were honored to the degree possible. In both composite samples, the IWAG process showed incremental recovery compared to the base case water and gas injection cases. The incremental recovery obtained (above 10% PV) was largely due to the reduction of gas relative permeability during three-phase flow. A maximum trapped gas saturation of 23% was used to history match the core-flood results.
A sector model of the Mauddud reservoir was run using the relative permeability and hysteresis model parameters obtained from the history matching of the composite core-floods. A water and gas flood base case was run and compared to the IWAG sequence. The IWAG process showed incremental recovery compared to the base case water injection. In the up-dip pattern where the water saturation is low, IWAG recovers 3% more than base case gas injection, while gas injection recovers 5% more than the IWAG sequence in the down-dip pattern where water saturation is higher.
The objective of introducing the Immiscible Water Alternating Gas process (IWAG) in Mauddud was to reduce gas production by controlling the mobility during the three-phase flow. Incremental oil, compared with gas and water injection was also to be evaluated. Three IWAG pilots were introduced after an extensive study on optimum locations. Two inverted 5-spot patterns and one line drive pattern were selected; each pattern is around 40 acre spacing, targeting Mauddud B interval. The original Water Alternating Gas (WAG) ratio was designed to be 1:3 (Water: Gas) and the WAG period was originally designed to be from three to six months based on simulation work. WAG ratio and duration optimization were subject to performance. After one year of cyclic injection, both inverted 5-spot patterns showed lack of response to the WAG cycles. In one of the two latter patterns, the water cycles critically affected oil production. In the line drive pattern, the WAG cycles initially showed a favorable response. After one year of injection, water and gas overcame oil production, leading to higher oil decline and the termination of the pilot due to confinement and operational issues.
Al-Murayri, Mohammed Taha (Kuwait Oil Company) | Al-Mayyan, Haya Ebrahim (Kuwait Oil Company) | Al-Ghnemi, Mohammad Faleh (Kuwait Oil Company) | Pitts, Malcolm (Surtek) | Dean, Elio (Surtek) | Wyatt, Kon (Surtek) | French, Josh (Surtek) | Skeans, Elii (Surtek)
Sabriyah Lower Burgan (SALB) is a multi-billion-barrel reservoir located in north Kuwait with favorable fluid and rock properties, and a strong active aquifer. The presence of the aquifer is advantageous for primary development of the reservoir but presents a challenge for conventional application of chemical EOR (CEOR). SALB has passed multiple stages of a CEOR evaluation process (technical screening, laboratory formulation design, SWCT, pilot design, risk assessment, etc.), and is currently considered for a multi-well CEOR pilot. This study investigates the viability of using sacrificial wells in the management of the lateral aquifer present in the SALB Layered formation, which represents a sought after CEOR target. The objective of these sacrificial wells is to reduce the potential negative impacts of the existing aquifer on commercial CEOR deployment.
The adopted approach involved using a history matched field model with EOR parameters calibrated to laboratory results for ASP and CO2 technologies. The multi-well field model was used to evaluate and compare different development scenarios to assess the impact of sacrificial wells. These scenarios were evaluated based on production performance and economics.
It was observed that strong aquifer presence complicates both CO2 and ASP project implementation. Challenges due to the aquifer include loss of EOR agents into the water leg, difficulty in accounting for effective pore volume of the project and water encroachment. It is difficult for EOR project economics to compete with an effective aquifer primary development. Sacrificial wells can be used to reduce the strength of the aquifer, potentially improving the effectiveness of the EOR technology. Although the sacrificial wells are unlikely to be economic on their own, they can improve the overall economics of the project. The amount of recovered oil due to EOR deployment is an important parameter to evaluate the economic feasibility of using sacrificial wells.
Many reservoirs around the world have strong aquifers, for which conventional reservoir engineering advice has been to avoid EOR application. This paper introduces a novel approach to deal with these strong aquifers by strategically placing wells that can reduce the aquifer's strength, thus making EOR deployment more favorable.
A heterogeneous and complex carbonate reservoir consists of many sub-layers. Each layer has unique characteristics. To enable comprehensive reservoir characterization, logging while-drilling technologies comprising high-resolution electrical imager, magnetic resonance and formation pressure tester were deployed. The integration of logging data had delivered detailed interpretation and proposes of a new workflow for best practice to advance reservoir performance and to optimize completion design.
Magnetic resonance was acquired with dual-wait time enabled T2 polarization to differentiate between moveable water and hydrocarbon. After acquisition, standard deliverables were porosity and permeability index. Porosity was divided into clay-bound water (CBW), bulk-volume irreducible (BVI) and bulk-volume moveable (BVM). Following good test results from the formation pressure tester, the permeability index from magnetic resonance was calibrated to mobility. Then rock quality was interpreted based on Lorenz Plot and permeability-calibrated to effective porosity ratio. The ratio was classified to high, low and no flow unit zones. The classification based on gradient of the ratio. Steeper gradient inferred high flow, lower gradient inferred low flow and flat gradient inferred no flow. To advance reservoir characterizations, flow unit zones were integrated to sedimentary facies interpretation. The interpretation was conducted based on high-resolution electrical imager.
The analyzed reservoir was divided in 23 flow units. The flow units were useful to identify reservoir compartments. Similar flow units were combined into one compartment. There are 3 intervals of high flow, 3 to 4 intervals of low flow and 4 intervals of no flow. The interval definition was used to design the completion. For best point of the completion within the intervals, high resolution electrical imager interpretation had added valuable input. Categories for best point in this particular study were homogeneous and less-cemented facies. The interval for best point would be varies based in completion strategy. The expectation result of the integrated logging data was to deliver maximum and stable flow rate with efficient completion design and advance the understanding of reservoir characterization. In addition, sedimentary facies interpretation was being correlated with the fluid flow behavior. In high-density cement intervals, permeability is low. In porous high-resistive sedimentary facies, the permeability is high. This inferred, the matrix and cement in the formation were affecting the fluid flow behavior.
The integration of logging data had resulted comprehensive reservoir characterization. The integration lead to completion optimization to advance reservoir performance and develop a comprehensive workflow. The workflow had combined petrophysical analysis, reservoir information and geological interpretation. This workflow would be best practice to be implement to advance complex carbonate reservoir and optimize completion strategy.
The shortage and high cost of CO2 and/or Hydrocarbon gases, in some areas, makes chemical EOR a practical option for tertiary oil recovery. Alkaline, Surfactant and Polymer, ASP, formulations continue to evolve to withstand challenges in relation to reservoir heterogeneity, complex mineralogy, high temperature and high formation water salinity of carbonate reservoirs. Such advanced ASP formulations have been considered to evaluate the performance of tertiary oil recovery process in a Kuwaiti carbonate reservoir. Successful performance has been seen in the lab through the evaluation of ASP coreflood experiments using composite carbonate cores. This paper presents the results of these coreflooding experiments and the steps followed to build representative ASP flooding simulation models as well as the workflow to calibrate these models to the observed experimental data. Moreover, the paper highlights the challenges associated with ASP coreflooding process and its modeling in the difficult environment of carbonate reservoirs. The paper also presents the techniques followed to overcome some of these challenges.
The modeling of two corefloods are presented in this paper, the first is for high-pressure live oil ASP coreflood, and the second is for low-pressure, surrogate oil ASP coreflood. The carbonate composite cores were first flooded with seawater down to residual oil saturation, Sorw. The ASP coreflood started with pre-flushing phase using softened seawater, followed by an ASP slug, and ended by injecting a number of pore volumes of polymer solution for mobility control. The representative ASP flooding simulation models of this paper captured the vital mechanisms involved in the ASP chemical EOR process, such as:
Micro-emulsion phase behavior, surfactant solubility ratios and resulting IFT changes Saponification process by the reaction of naphthenic acids of the crude oil with the injected alkali Adsorption of surfactant and polymer on the carbonate rocks as a function of pH and time The geochemistry of aqueous and oleic phase reactions Updating reservoir capillary number, resulting from the changes to IFT and wettability Effect of changes in capillary number is reflected by different sets of interpolation Kr curves The rheological behavior of polymer solutions Optimum salinity and salinity gradient effect.
Micro-emulsion phase behavior, surfactant solubility ratios and resulting IFT changes
Saponification process by the reaction of naphthenic acids of the crude oil with the injected alkali
Adsorption of surfactant and polymer on the carbonate rocks as a function of pH and time
The geochemistry of aqueous and oleic phase reactions
Updating reservoir capillary number, resulting from the changes to IFT and wettability
Effect of changes in capillary number is reflected by different sets of interpolation Kr curves
The rheological behavior of polymer solutions
Optimum salinity and salinity gradient effect.
Assisted history matching software was employed in the calibration of the two corefloods following a stepwise procedure by first matching the water flood results, then matching the surfactant production values, and finally matching the remainder of the ASP flood results. This paper discusses the parameters that needed to be tuned in order to attain a match of both waterflood and ASP flood results. The matched results included the oil recovery, flow pressure differential, and the concentration of chemical effluents traced during the experiments. The profile of ASP oil recovery in these carbonate composite cores is more gradual, and is different from those observed in sandstone corefloods.
Beheiry, Karim (Halliburton) | Al Mulaifi, Mohammed (Kuwait Oil Company) | Sekhri, Anish (Kuwait Oil Company) | Farhi, Nadir (Halliburton) | Nouh, Walid (Halliburton) | Abdel Naby, Ahmed (Halliburton) | Marafi, Abdullah (Kuwait Oil Company) | Shatta, Atef (Kuwait Oil Company) | Al-Ali, Hussain (Kuwait Oil Company)
The 12-1/4-in. directional application is one of the most challenging applications in North Kuwait. The section requires drilling from the Mutriba (Santonian) to Burgan (Albina) formations through highly interbedded, high-compressive-strength carbonates (limestone and dolomite), sandstones, and shales. In recent years, Kuwait Oil Company (KOC) has tested many different bit designs in an attempt to minimize stick/slip vibrations and maximize the rate of penetration (ROP). This paper presents the technology used to nearly eliminate stick/slip vibrations, leading to a field record (and a consistent performance) for this application, as well as the process used to develop the technology.
The interval was drilled using a rotary steerable system (RSS) to maximize wellbore quality and to provide consistent build-up rates (BUR) required. Parameters run in this application are often limited because stick/slip becomes uncontrollable when transitioning through the many formation types. In addition, reactive and stressed caving shales are regularly observed in the Ahmadi and Wara formations drilled during the interval. Special care is needed to mitigate these drilling challenges and to successfully drill the interval with low stick/slip vibrations and high ROP.
Using proprietary state-of-the-art design and analysis technologies, a new polycrystalline diamond compact (PDC) bit was designed for use specifically with RSS tools to minimize the vibrations. The solution required a thorough offset analysis before the interval that was presented using the design process. The design process enabled the presentation of a driller's roadmap to be used in conjunction with the new bit to enable a benchmark ROP to be achieved.
The use of the newly designed PDC bit produced minimal torsional vibrations, enabling a 62% increase in ROP over the field average. This increased ROP resulted in a savings of USD 90,000, reducing the cost per foot by 33%, as compared to the field average. The bit also came out in excellent condition, enabling future use in similar applications for KOC.