Excess fluid leak-off, a challenge in Kuwait's naturally fractured tight carbonate formations, can compromise post-fracture productivity. Past acid fracture treatments, both for moderate and high temperature formations failed to generate the long differently etched fracture due to excessive leak-off. Treating zones with multiple perforated intervals in a single stage, particularly in pay zones with long heterogeneous rock properties can result in non optimal stimulation. Therefore, a new approach was developed with proven success to enhance fracture conductivity and overall production by efficient control of fluid leak-off. This novel approach incorporates the use of far-field and near-wellbore diverting systems into the acid fracture design. These solid particulate diverters (SPD) include low and high temperature systems that provide enhanced near-wellbore diversion in both case and open-hole applications. The SPD are designed to bridge across perforations and fractures in the higher permeability zones, diverting the stimulation fluid into lower permeability zones. A smaller sized multi-modal distribution of SPD controls the fluid in narrower natural fractures and wormholes, deepening penetration of the stimulation fluid along the entire fracture length. The SPD agents are fully degradable and do not contribute to permeability loss of the created fracture or the perforated interval when production starts. The production of the wells where the SPD agents were applied were higher in comparison to expected production of offset wells where non-acid crosslinked fracturing pad stages alternated with gelled or emulsified acid, and visco-elastic surfactant (VES) slugs. Both crosslinked fracturing pads, VES and emulsified acid slugs do not effectly control live acid leak off. Two case histories, documenting successes where this new approach to acid fracturing has been applied in the Tuba and Middle Marrat formations, have superior production results that correspond to enhanced fracture geometry.
Proppant fracturing treatments in sandstone formations are routinely executed in Kuwait, however when carbonate formations are the target, acid fracturing is the preferred treatment method. It has been observed that acid fracturing delivers a high initial production however maintaining a sustainable production rate is a challenge in the tight cretaceous carbonate formations in Kuwait. A production enhancement technique needed to be identified in order to deliver more sustainable production and maximize recovery from these carbonate formations. The first stage of the project focused on ascertaining the operational feasibility of proppant fracturing in a single layered Mauddud reservoir. This paper will focus on the operational implementation of multi-stage proppant fracturing in the multi-layered Tuba reservoir. (Nagarkoti, M., et al., 2018) Based on global experience it was proposed that proppant fracturing can deliver more sustainable production rate as compared to acid fracturing. A predominant issue in previous acid fracturing treatments done in the Tuba reservoir has been fracture containment between layers. Proppant fracturing was also identified as a solution to mitigate this challenge. Proppant fracturing had been previously attempted in Kuwait, however the attempts were evaluated as not being operationally successful. The steps that lead to the recent first successfully executed proppant fracturing treatment in carbonates in Kuwait has been documented in Part I of this paper series. The cretaceous carbonate formations in North Kuwait are relatively shallow and are known to be tight and highly ductile. Due to the ductility of these formations, proppant placement and reduction of the fracture conductivity due proppant embedment were thought to be significant risks. During the course of the project, detailed core analysis and testing was conducted using formation core samples to ascertain the severity of this risk. Lessons learnt in the first stage of this project were implemented prior execution to ensure that the planned proppant fracturing treatment would meet or exceed operational expectations. Successful execution of this hydraulic fracturing treatment was pivotal in order to plan the future production strategies for the Tuba formation. A cautious approach needed to be followed as proppant placement was of paramount importance. Different strategies were incorporated in the fracturing workflow to ensure the success of the treatment and to maximize data collection in order to optimize future treatments and well placement. Multiple mini-fracs, temperature logs and pumping of novel non-radioactive tracer proppant were some of the techniques utilized. During execution various decisions were taken real-time to ensure success of the treatment. It was observed that all parameters were consistent with the results of the core and laboratory testing conducted during the initial phase of the project which lead to optimizing the proppant placement. The success of this treatment has been a game changer resulting in more wells being identified as candidates for proppant fracturing in this field. Once proppant placement was established in the first stage of this project, an attempt was made to optimize fracture designs, fluids and treatment schedules. The lessons from these optimizations will help further design implementations in the next phase of this project including fracturing of horizontal multi-stage wells which will help ascertain the future production enhancement strategy for this field.
Proppant fracturing treatments in sandstone formations are routinely executed in Kuwait, however when carbonate formations are the target, acid fracturing is the preferred treatment method. It has been observed that acid fracturing delivers a high initial production however maintaining a sustainable production rate is a challenge in the tight cretaceous carbonate formations in Kuwait. A production enhancement technique needed to be identified in order to deliver more sustainable production and maximize recovery from these carbonate formations. Based on global experience it was proposed that proppant fracturing can deliver more sustainable production rate as compared to acid fracturing. Proppant fracturing had been previously attempted on two occasions in Kuwait, however both the attempts were evaluated as not being operationally successful. Hence prior to executing the first successful proppant fracturing treatment in carbonates in Kuwait a thorough study was undertaken to identify and mitigate the possible risks. The cretaceous carbonate formations in North Kuwait are relatively shallow and are known to be tight and highly ductile. Due to the ductility of these formations, proppant placement and reduction of the fracture conductivity due proppant embedment were thought to be significant risks. During the course of the project, detailed core analysis and testing was conducted using formation core samples to ascertain the severity of this risk. Successful execution of this hydraulic fracturing treatment was pivotal in order to plan the future production strategies from these formations. A cautious approach needed to be followed as proppant placement was of paramount importance. Different strategies were incorporated in the fracturing workflow to ensure the success of the treatment and to maximize data collection in order to optimize future treatments and well placement. Multiple mini-fracs, temperature logs and pumping of novel non-radioactive tracer proppant were some of the techniques utilized. During execution various decisions were taken real-time to ensure success of the treatment. It was observed that all parameters were consistent with the results of the core and laboratory testing conducted during the initial phase of the project which lead to optimizing the proppant placement. The success of this treatment has been a game changer resulting in more wells being identified as candidates for proppant fracturing in this field. Now that proppant placement has been established the objective of future treatments is to optimize fracture designs, fluids and treatment schedules which will help the future production enhancement strategy for this field. Lessons learnt from this first successful well will be applied to future wells planned in carbonate reservoirs in Kuwait, in order to maximize recovery.
Integrated field development studies were performed to increase oil recovery from the Marrat reservoir in the Umm Gudair field, a large, low permeability, complex, naturally fractured and highly faulted carbonate reservoir. The studies involved rebuilding the static model, creating and history matching a new dynamic model and using it to examine redevelopment scenarios. These included well interventions and workovers under primary depletion, secondary waterflood and, following a screening exercise, low salinity flooding (LSF). A new structural interpretation of 3D seismic data provided a revised static geological model and yielded insight into the number, geometry and origin of the many faults intersecting the reservoir. Rock types defined from core analysis were distributed in the static geological model using trends from Bayesian lithofacies classification based on pre-stack inversion of seismic data. Porosity and permeability were modelled by rock type. Saturation-height functions for each rock type were developed from mercury injection capillary pressure (MICP) data; and the reservoir free water level was varied so that these functions honoured the log-based water saturation interpretation. The dynamic model input description was based on available and interpreted data for the assumed oil wet reservoir. The history matching was aided by sophisticated application of decline curve analysis (DCA) and used an Opportunity Index approach to optimise well placement. The history matching led to a simplified and effective solution for characterising the locally naturally fractured reservoir nature. The effect of high permeabilities associated with increased fracture density was accommodated by introducing facies-based and distance from fault-related permeability modifiers, while maintaining geological rigour. The dynamic model was used to examine a range of field redevelopment scenarios. This showed that LSF could enhance field recovery and achieve a three-fold increase in estimated ultimate recovery, in conjunction with other improved reservoir management strategies. The results provided support for specialised laboratory and dynamic modelling investigations as a precursor to LSF pilot trials. A low cost source of LSF injectant was identified which could contribute to lowering the overall carbon footprint.
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