Mauddud Formation is a major oil-producing reservoir in Raudhatain Field of North Kuwait. The Mauddud Formation is an early Albian in age and it was generated an environment of the shallow-water carbonate and consists of Grainstones, Wackestones and Mudstones deposited in ramp settings. In Raudhatain field (RAMA) is undertaking massive development efforts with planned enhancement in Oil production. Reservoir description and distribution of rock properties in 3D space are challenging due to inherent reservoir heterogeneity, in this case primarily driven by depositional and diagenetic patterns.
KOC North Kuwait Reservoir Studies Team (NK RST) has been challenged to increase the production from several key NK oil fields. To achieve this goal, KOC has partnered with Schlumberger to rebuild integrated model with Petrophysics, Geophysics, and Geology and Reservoir data of the Mauddud Reservoir. The original model was required to minimize challenges in new infill locations, increase Oil recovery factor and detect water breakthrough to minimize water production. One of the key issues in creating RAMA reservoir model is integration of all available data in identifying the horizontal permeability, reservoir heterogeneity and identification of thief zones.
A fine Geological grid model with 35M cells, 10 Geological horizons has been built to characterize the Mauddud reservoirs of the RAMA field including the permeability from PLT logs combined with petrophysical and lithological / facies data to add more understanding of the distribution of reservoir properties. Log response group methodology and the undeveloped area in the Saddle (structurally low area) has been modelled for the first time in Raudhatain NK Field. This combined study utilizes the available data and cutting-edge technology using Geo2Flow which resulted in fluid compartmentalization and free water level identification. STOOIP has been upgraded and unlocking potential in new segments of the developed field. The original model was built based on vertical/Deviation wells (345) which lead to discrepancies in the structural interpretation. The new update has been carried out including all horizontal wells to minimize the uncertainty in the structure framework.
Al-Azmi, Mejbel Saad (Kuwait Oil Company) | Al-Otaibi, Fahad (Kuwait Oil Company) | Kumar, Joshi Girija (Kuwait Oil Company) | Tiwary, Devendra (Kuwait Oil Company) | Al-Ashwak, Samar (Kuwait Oil Company) | Dzhaykiev, Bekdaulet (Baker Hughes, a GE Company) | Shinde, Neha (Baker Hughes, a GE Company) | Hardman, Douglas (Baker Hughes, a GE Company) | Noueihed, Rabih (Baker Hughes, a GE Company) | Gadkari, Shreerang (Baker Hughes, a GE Company)
The complex nature of the reservoir dictated comprehensive formation evaluation logging that was typically done on wireline. The high angle designed for maximum reservoir exposure, high temperature, high pressure (HTHP), differential reservoir pressure and wellbore stability challenges necessitated a new approach to overall formation evaluation. The paper outlines Formation Evaluation strategy that reduced risk, increased efficiency and saved money, while ensuring high quality data collection, integration and interpretation.
After review of all risks, a decision to utilize Managed Pressure Drilling (MPD) for wellbore stability, Logging While Drilling (LWD) to replace wireline and Advanced Mudlogging Services was implemented. The Formation Evaluation team utilized LWD resistivity, neutron, density and nuclear magnetic resonance logs supplemented with x-ray diffraction (XRD), x-ray fluorescence (XRF) and advanced mud gas analysis to ensure comprehensive analysis. The paper outlines workflows and procedures necessary to ensure all data from LWD, XRF, XRD and mud gas are integrated properly for the analysis.
Effects of Managed Pressure Drilling on mud gas interpretation as well as cuttings and mud gas depth matching are addressed. Depth matching of all data, mud gasses, cuttings and logs are critical for detailed and accurate analysis and techniques are discussed that ensure consistent results. Complex mineralogy due to digenesis and effect of LWD logs are evident and only reconciled by detailed XRF and XRD data. The effects of some conductive mineralogy are so dramatic as to infer tool function compromise. The ability to determine acceptable tool response from tool failures eliminates unnecessary trips and leads to efficient operations. The final result of the above data collection, QC and processing resulted in a comprehensive formation evaluation interpretation of high confidence.
Finally, conclusions and recommendations are summarized to provide guidelines in Formation Evaluation in similar challenging highly deviated, HTHP, complex reservoir environments on land and offshore.
Anis, Apollinaris Stefanus Leo (Schlumberger) | Syarif, Zilman (Saka Indonesia Pangkah Limited) | Setiawan, Ade Surya (Schlumberger) | Hidayat, Azalea (Saka Indonesia Pangkah Limited) | Murtani, Anom Seto (Saka Indonesia Pangkah Limited)
Ujung Pangkah Field which located at offshore East Java Indonesia, is known for its challenging nature from geological, reservoir and drilling perspectives. Drilling experiences in this area shows severe wellbore instability in overburden shale and in fractured carbonate reservoir. Hydrocarbon production directly exacerbate drilling problems and production issues that were not expected came earlier than predicted, for example early water breakthrough. At least two or three operators facing similar severe wellbore instability problems in the area.
Due to the complexity of subsurface systems and coupled interactions between depletion and stresses, the present-day stress state in Ujung Pangkah Field which have undergone production will be different from the pre-production stress state. Therefore, a comprehensive analysis will require numerical modelling involving coupling of 3D geomechanical model with fluid flow during production operations from dynamic model. Present-day stress state is subsequently used for wellbore stability analysis of planned development wells in Ujung Pangkah Field. Investigation of the behavior of natural fractured reservoir during depletion and its impact to reservoir management is also attempted. Two-way coupling of geomechanic and dynamic models were conducted whereby porosity and permeability update due to production were simulated based on uniaxial pore volume compressibility tests. Hence, porosity and permeability of fractures are not considered static anymore but dynamic due to stresses changes and production.
The result of coupled simulation is able to reduce wellbore instabilities significantly in the planned well. The stable mud weight windows for planned wells are extracted from the model. The stable mud weight window in the reservoir interval is narrow to no stable drilling window in all the planned wells due to depletion. In general, the preferred direction to drill, requiring lowest mud weights, is in the direction of minimum horizontal stress which in this case is Northwest-Southeast (NW-SE). However, it was found that azimuthal dependency of mud weight is insignificant due to low horizontal stress anisotropy.
Reservoir compaction and sea-bed subsidence were also calculated using the outputs from the model. The result is useful for completion and platform integrity.
Tuba is tight carbonate reservoir and one of largest Upcoming Reservoirs in North Kuwait Sabriyah field and subdivided to three main reservoir units (upper, middle and lower). Tuba, though discovered in the 60's, is still relatively under-exploited presently with only ±10 active oil producer wells with very low total production rate compared to other major reservoirs in same field. High reservoir heterogeneity, tightness, and poor fluid properties necessitate the application of fracturing stimulation technology to maximize Conductivity and hence recovery enhancement. Recent technologies in multistage acid Fracturing executed successfully covering multiple layers as first time ever in one of existing two Tuba horizontal wells.
The well under study is highly deviated, completed as barefoot in the Upper Tuba reservoir, intersecting multiple sub-layers. Following the positive results of acid fracturing treatments in offset Tuba's vertical wells, the candidate well was selected for first multistage acid fracturing in horizontal wells, to setup the reservoir development plan ensuring high production potential with most cost-effective drilling and completion strategies. Rig-less 5-Stages Acid Fracture treatment was executed in flawless operation. Many technical and operational challenges were faced (Geo-mechanics, stages selection and design, cementing 7in liner) and properly handled within integrated teams with lessons learned are to be considered in next designs and executions. Initial post multistage acid Frack short term production showed productivity improvement by approximately 5 folds of pre-stimulation production. The well showed high decline in production rate within the first one-year production post fracturing stimulation. However, analysis showed that the decline mainly was caused by reservoir depletion rather than fracture conductivity deterioration. The well is under close monitoring for stabilization (rate and pressure). Horizontal PLT is planned to evaluate inflow profile from individual layers to improve next designs.
Despite the close results yilded from the multistage acid fracturing in two horizontal wells compared to the results from 7 vertical wells, it is still early to evaluate stimulation potential of horizontal against vertical wells. It needs more production history and more wells to evaluate long term sustainability.
Water-flooding is planned to support reservoir development and enhancing stimulation sustainability and by turn recovery factory. First pilot water flooding injector well was commissioned in early 2018, but comprehensive waterflooding analysis is not finalized yet.
The initial positive results of first multistage acid fracturing in Tuba reservoir had key contribution to setup Development strategy for the entire TUBA reservoir to expand drilling horizontal wells and complete it with initial multistage fract (MSF) stimulation to maximize reservoir exposure and enhance reservoior productivity that will contribute significantly to the NK production target. Two more horizontal wells were drilled and completed with MSF in late 2018 with initial encouraging enhanced productivity results during cleaning and lifting but were not put yet on production for more comprehensive analysis. ation to improve initial productivity.
In the current and future scenario of increasing demand for hydrocarbons, Multi-Disciplinary Integrated Reservoir Management team is the key to achieve maximum production rates and ultimate recovery. In Raudhatain Upper Burgan reservoir production started in 1959 with initial reservoir pressure of 3850 psi. Decline in reservoir pressure with sustained rate of production indicated weak aquifer support and initiated water injection during the year 2001 with three flank injectors. Production rate was sustained at 30 to 35 MBOPD for long time and it was decided that to go the next level of production and to meet KOC's strategic production target.
Various alternative pressures – production plans were scrutinized by the multi-disciplinary team consists of Geologists, Reservoir Engineers, Petrophysicists and Petroleum Engineers and identified bottlenecks, constraints and action plan to address the problems and to accelerate the production. Some of the bottlenecks to accelerate the production were decreasing pressure, unavailability of required volume of water for injection, delay in commissioning of effluent water injection facility and low productivity of flank wells with viscous oil. The integrated Reservoir management team initiated number of projects to increase the productivity like Paradigm shift in drilling practice by way of drilling Horizontal, Multilateral wells and completing with ICD's for better production and injection sweep efficiency. Liquidated the sick wells with no potential in any other Reservoirs (Multiple Reservoirs) are identified for Horizontal Sidetracking to sweet spot areas. Decreasing Reservoir pressure and Voidage Replacement Ratio has been addressed by changing the water injection strategy and aligning the injectors in right areas.
The results were rewarding as the production rate doubled from a sustained level of 35 MBOPD to more than 70 MBOPD in a span of 3 to 4 years. The initiatives taken to convert the producers to injectors resulted in increased water injection volume and doubled the Voidage Replacement Ratio.
This paper presents the details of Integrated Reservoir Management team efforts and what are the initiatives and strategic actions taken by overcoming the current constraints to double its production. It discusses the effective Reservoir Management of a mature oil field to enhance and accelerate production.
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.
One of the North Kuwait Carbonate fields which starts its production in 1957 has very low recovery factor after 60 years of production although the field was under water flooding since 1997. A workflow was developed to first understand the reason behind the low recovery and second to propose the best way to improve it.
The workflow starts with first building a material balance model to understand the main reservoir driving mechanisms. Second, a fine-scale history matched simulation model was used to understand the main reasons of the current low recovery. A Produce High and Inject Low (PHIL) concept was proposed with locating all the injectors at the deepest zone and the producers at the shallow zones. Finally, the proposed PHIL concept with inverted 5-spot horizontal wells was examined compared to the inverted 9-spot vertical wells and to the peripheral PHIL concept using the simulation model to examine the best approach to maximize the recovery.
Different outcomes from the above-mentioned workflow can be summarized as follows; first, it was found that the main driving mechanism is water injection which represents 70% of the reservoir recovery factor. Hence the importance of creating an artificial aquifer along the whole area of the field to provide the required pressure support which calls for the implementation of the PHIL concept with inverted 5-spot pattern background as the best development concept for the field. Second, the thorough data review used on building the fine-scale model shows that the current recovery is dominated by single zone which represents only 15 % of the in-place and on top of this, it was found that all the developed wells are located only on 30% of the field leaving 70% of the field undeveloped. These are the main reasons behind the low recovery. Finally, the developed PHIL concept with inverted 5-spot background shows that the recovery can be increased by five times with less number of new wells and less water injection volume required compared to the 9-spot vertical wells and the peripheral PHIL concepts. This five-folds increase in recovery encourages the asset to do a pilot to implement the proposed development strategy.
Unlike the commonly used inverted 5-spot vertical wells, this work proposes a novel approach of inverted 5-spot horizontal wells with directing the horizontal injectors at the deepest zones and the horizontal producers at the shallow zones. Hence creating an artificial bottom aquifer with minimizing the water production and maximizing the water injection distribution along the whole area of the reservoir.
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.