Multimodal Carbonates: Distribution of Oil Saturation in the Microporous Rock Regions

Improved oil recovery from tight carbonate formations may provide the world with a major source of lower-rate power over several decades. Here we provide an overview of the Arab D formation in the largest oil field on earth, the Ghawar. We investigate the occurrence of microporosity of different origins and sizes using scanning electron microscopy (SEM) and pore casting techniques. Then, we present a robust calculation of the probability of invasion and oil saturation distribution in the nested micropores using mercury injection capillary pressure data available in the literature. We show that large portions of the micropores in Arab D formation would have been bypassed during primary drainage unless the invading crude oil ganglia were sufficiently long. Considering the asphaltenic nature of oil in the Ghawar, we expect the invaded portions of the pores to turn mixed-wet, thus becoming inaccessible to waterflooding until further measures are taken to modify the system’s chemistry.

Insights on Fractured Domains in Reservoirs Resulting from Modeling Complex Geology/Structures - Case Study of the Ratana Field in the Potwar Basin, Pakistan

Exploration success in fold-and-thrust belts, like the Potwar petroleum province, is impacted by seismic imaging challenges and structural complexity. Success partly relies on the ability to validate subsurface models and model a range of properties, such as reservoir permeability. This is particularly important in the case of tight carbonate reservoirs such as the Eocene Sakesar Formation, where the recovery of economic quantities of hydrocarbons is conditioned by the presence of fracture-enhanced permeability. This requires the application of geological and geophysical modeling techniques to address these challenges, to minimize uncertainty and drive exploration success. The interpretation and structural validation of the Ratana structure presented here allows the proposal of a consistent and robust structural model even in areas of higher uncertainty in the data, such as along faults. The dynamically updatable, watertight, complex 3D structural framework created for the top Sakesar reservoir was used in combination with an assisted fault interpretation algorithm to characterize the fault and fracture pattern. The results showed a higher density of high amplitude fractures on the flanks of the structure rather than along the hinge. These results are supported by the incremental strain modeling based on the kinematic evolution of the structure. Together, this helped to characterize potential fracture corridors in areas of the seismic volume that previously proved challenging for human driven interpretation. Our results allow us to reduce the uncertainty related to the geometrical characteristics of the reservoir and provide insights into potential exploration well targets to maximize chances of success, suggesting that permeability and hydrocarbon flow may be higher at the margins of the Ratana structure, and not at the crest, which was the focus of previous exploration and production efforts.

New Perspectives for Acidizing Tight Carbonate Oil Producers Completed Across an Extended Openhole Horizontal Section

Over the past decade, coiled tubing (CT) has been one of the preferred fluid conveyance techniques in tight carbonate oil producers completed with an uncased horizontal section. In the onshore Middle East, conventional CT stimulation practices have delivered inconsistent results in that work environment. This is mainly due to a mix of reservoir heterogeneity, limited CT reach, lower CT pumping rates, uncontrolled fluid placement, and uncertainty of downhole dynamics during the stimulation operations. An intervention workflow recently validated in onshore Middle East to acidize tight carbonate openhole horizontal water injectors was introduced for the first time in an oil producer. The advanced stimulation methodology relies on CT equipped with fiber optics to visualize original fluid coverage across the openhole interval through distributed temperature sensing (DTS). Real-time downhole telemetry is used to control actuation of CT toolstring components and to understand changing downhole conditions. Based on the prestimulation DTS survey, the open hole is segmented into sections requiring different levels of stimulation, fluid placement techniques, and diversion requirements. The candidate carbonate oil producer featured an average permeability of 1.5 md along 8,003 ft of 6-in. uncased horizontal section. Because of the horizontal drain's extended length and the presence of a minimum restriction of 2.365-in in the 3 1/2-in. production tubing, a newly developed CT slim tractor was essential to overcome reach limitations. In addition, a customized drop-ball high-pressure jetting nozzle was coupled to the extended reach assembly to enable high-energy, pinpoint acidizing in the same run. The instrumented CT was initially run until lockup depth, covering only 53% of the horizontal section. The CT slim tractor was then precisely controlled by leveraging real-time downhole force readings, enabling full reach across the open hole. Prestimulation DTS allowed identification of high- and low-intake zones, which enabled informed adjustments of the acidizing schedule, and in particular the level of jetting required in each section. After its actuation via drop-ball, the high-pressure jetting nozzle was operated using downhole pressure readings to ensure optimum jetting conditions and avoid exceeding the fracturing threshold. Upon completion of the stimulation stage, post-stimulation DTS provided an evaluation of the fluid placement effectiveness. After several weeks of production, the oil rate still exceeded the operator's expectations fivefold. This intervention validates the applicability of the advanced matrix stimulation workflow in tight carbonate oil producers completed across a long openhole horizontal interval. It also confirms the value of real-time downhole telemetry for optimal operation of extended reach toolstrings and the understanding of the downhole dynamics throughout stimulation treatments, the combination of which ultimately delivers breakthrough production improvements compared to conventional stimulation approaches, in a sustainable manner.

Unconventional Drilling and Creative Solutions Delivered World Record a Multi-Laterals Fishbone all Legs Drilled, Accessed and Stimulated First Attempt - Case Study from Kuwait

Despite being the first area for oil to be found in Kuwait in mid 1930's, Bahra's oil production remained largely unexploited until 2015, when a major development campaign targeting one of its tight carbonate reservoirs through horizontal drilling and multi-stage frack completions was commissioned. Nonetheless, with the development and exploration initiatives underway, surface congestion is the primary challenge. As the number of wells increased the need for unconventional well profiles became more demanding. The multi-lateral fishbone approach was designed to have a total of four laterals with approximately 3000 ft each. Lessons learned from previous level-1 multi-laterals drilled in North Kuwait indicated that the primary challenge remained to be the ability to drill a smooth bore hole profile across the junctions to successfully re-access and stimulate all the drilled legs with coil-tubing to maximize production. Kuwaiti Operator Reservoir and study team were looking for an alternate solution to increase the production in Bahra using multi-laterals technics in the same reservoir to stimulate and sustain production in calcite reservoir. Historically only three wells were drilled experimenting challenges and failures to open hole sidetrack leading to have long time to complete the wells with maximum 3 legs as record including the mother hole. RST team asked to drill a well with 4 legs, each leg following the same azimuth with the condition to be 300 ft apart. The thorough planning exercise completed and the close follow-up to the approved design of service during execution phase resulted in the successful delivery of the first four legs fishbone in Kuwait with Zero Non-Productive Time. In addition to achieving all the geological targets, the smooth borehole profile helped ensure successful re-entry and stimulation of all four legs in the same run achieving the well challenge using the unique

Laboratory Measurements Mapping Heterogeneity and Variation of Poroelasticity for Improved Hydraulic Fracture Design in a Tight Carbonate Reservoir Onshore UAE

Reservoir X is a thin and tight carbonate reservoir with thin caprock that isolates it from an adjacent giant reservoir. An accurate geomechanical model with high precision is required for designing the optimum hydraulic fracture and preventing communication with adjacent reservoirs. The reservoir exhibits considerable variability in rock properties that will affect fracture height growth, complexity, and width and rock interaction with treatment fluids. The heterogeneity observed from the tight sections is further complicated by the variation of Biot's poroelastic coefficient, α, which is required for accurate assessment of the effective stresses. Laboratory testing was required to characterize the extensive vertical heterogeneity for key inputs in developing a geomechanics model. Approximately 120 ft of continuous core from an onshore field was provided for this study. The core material represented a potential tight carbonate reservoir interval and bounding sections. Heterogeneity mapping was performed from continuous core measurements from CT-imaging and scratch testing. CT-imaging provides an indication of the bulk density variation and compositional changes. Scratch testing provides a continuous measure of the unconfined compressive strength (UCS). Combining the two provides a means for accurate definition of rock thickness for dense, moderately dense, and lower density material coupled with corresponding compressive strength. Rock units were then subdivided based on these continuous properties for further geomechanics tests. Using log analysis combined with continuous UCS measurements from scratch testing, eight rock type classes were defined covering the target reservoir interval and bounding sections. This information was used for optimizing the sample selection process to characterize each identified rock unit. Routine core analysis measurements reveal significant vertical heterogeneity with porosity ranging from 0.1% to 18.1%. Similar variability was determined from elastic properties for each of the eight rock types. Quasi-static values for Young's modulus and Poisson's ratio determined at in-situ stress conditions ranged from 2.6 to 9.6 × 106 psi, and from 0.16 to 0.34, respectively. The Biot's poroelastic coefficient has a first-order impact on the calculated effective stress profile, which directly affects fracture stimulation model results. Testing from this study combined with previous measurements (Noufal et al. 2020, SPE-202866-MS) provides a unique correlation with porosity and bulk compressibility. In addition, rock-fluid compatibility was evaluated with proppant embedment/fracture conductivity tests. Results are dependent on a given rock type, exhibiting a wide range of fracture conductivity as a function of closure stress from 10 to 1000 md-ft. Embedment for all cases was low to moderate.

Challenges and Achievements of Drilling Record MRC Wells for Appraising and Developing an Offshore Tight Carbonate

This paper describes the field development planning strategy for appraising and developing an offshore reservoir area via extended reach extra-long maximum reservoir contact laterals drilled from an artificial island. These single production and injection laterals are completed in excess of 20,000 ft on top of tens of thousands feet of drilled well path to reach the drain landing point. These laterals have a dual purpose, as in addition to reservoir appraisal, is to maximize the productivity and injectivity in an on-going development of a tight carbonate reservoir. The well planning process starts from a careful selection of reservoir target coordinates to maximize the oil in place being developed from the artificial island and to enable reservoir testing and appraisal. From this data, initial 3D well designs are generated based on island location and rig capability to ensure ability to drill and run completion to total depth. The generated well tracks are used in a reservoir model to forecast production uplifts and inflow/outflow profiling along laterals. A strategic drilling step-out program has been implemented to extend drilling reach and completion deployment incrementally along with a reservoir surveillance program. The program was designed with built-in risk mitigations for any potential drilling and completion issues. The implemented program has enabled drilling into new areas and testing the reservoir properties at a small incremental cost of extending horizontal laterals. This has led to huge cost savings versus a very expensive appraisal program from a wellhead platform that included drilling a new well in addition to topside facility changes and pipelines conversions along with associated maintenance costs. The data gathered from these wells have enabled reduction of geologic uncertainty and de-risking of future developments. As a result, the field development footprint of developed oil resources was extended by additional 20% without the requirement of building additional drilling structures. Additionally, there is a well count reduction via lateral extension thus leading to capital costs saving. There were initial challenges encountered during lower completion deployment but they were resolved successfully in subsequent wells. An outcome of this strategy was the successful drilling of maximum reservoir contact wells with tens of thousands feet of drilled well path to reach the drain landing point and then with single horizontal drains exceeding 20,000 ft. The drilled wells resulted in unprecedented records in UAE and globally in terms of well total length, horizontal drain length and completion deployment.

Application of Techniques of Natural Fracture Characterization for Appraisal of Tight Carbonate Reservoirs: A Case Study From Jurassic of Kuwait

The State of Kuwait is currently appraising and successfully developing the tight carbonates reservoirs of Jurassic age, which have very low matrix porosity and permeability. These reservoirs are affected by several tectonic events of faulting and folding, resulting in the development of interconnected natural fractures, which provide effective permeability to the reservoirs in form of production sweet spots. The objective of the study was to characterize the natural fractures and identify high permeability sweet spots as being appraisal drilling locations in a discovered field with tight carbonate reservoirs. An integrated approach was undertaken for building a discrete fracture network model by characterizing the developed faulting- and folding-related fractures and combining all subsurface data from multiple domains. The reservoir structure has a doubly plunging anticline at the field level that is affected by several strike-slip faults. The faulting-related fractures were characterized by generating multiple structural seismic attributes, highlighting subsurface discontinuities and fracture corridors. The folding-related fractures were modelled using structural restoration techniques by computing stresses resulting from the anticlinal folding. The fracture model was built in addition to the 3D matrix property model for this tight carbonate reservoir, resulting in a dual-porosity-permeability static model. Analogue data was used to compute fracture aperture and expected fracture porosity and permeability, to identify the sweet spots. Structural seismic attributes such as Ant Tracking and Consistent Dip were successful in highlighting and identifying the fault lineaments and fracture corridors. The seismic discontinuities were validated using the fractures interpreted in the image log data from the predrilled wells before being input into the fracture model. Paleo stresses, derived from structural restoration, were combined with the reservoir facies and geomechanical properties to gain important insight into predicting fractures developed due to folding. Several fracture aperture scenarios were run to capture the uncertainty associated with the computed fracture porosity and permeability. Based on the results, several sweet spots were identified, which were ranked based on their extent and connected volumes of the various permeability cases. Identifying these sweet spots helped make informed decisions regarding well planning and drilling sequence. High-inclination wells aligned parallel to the present-day maximum stress direction were proposed, which would cut across corridors of the predicted open fractures. Through this study, comprehensive fracture characterization and fracture permeability understanding of the tight carbonates in the field under study were successfully achieved. This workflow will be useful in exploratory or appraisal fields with tight carbonate reservoirs.

An Innovative Approach to Install Production String with ESP to Avoid Productivity Impairment in Multistage Fractured Horizontal Well

Objectives/Scope Generally, tight reservoirs require hydraulic fracturing to enhance and sustain hydrocarbon production. However, fracturing requires frac string with bigger Internal Diameter (ID) to minimize frictional losses during hydraulic fracturing operation. This string ID may not be suitable to provide optimum Vertical Lift Performance (VLP) during production phase, particularly in oil wells. Therefore, it is required to replace the frac string with production string of smaller ID. Occasionally, artificial lift also becomes essential to overcome VLP issues in future due to progressive water production and declining reservoir pressure. Methods, Procedures, Process Completion replacement often causes reservoir damage due to killing operation, which can be removed in conventional carbonate reservoirs by matrix stimulation. However, formation damage removal is difficult in hydraulically fractured tight carbonate and sandstone reservoirs. Preventive measures become essential to avoid productivity impairment particularly in hydraulically fractured reservoirs. Different preventative options are proposed and reviewed to isolate reservoir with their advantages and disadvantages. After comprehensive studies and risk assessments, an innovative modification in the completion plan was introduced and finalized. This plan includes production string with Electrical Submersible Pump (ESP) to improve VLP. This completion provides full accessibility intervention job, which may be required for reservoir monitoring and surveillance in future. Results, Observations, Conclusions A comprehensive production test is performed to evaluate and compare the testing results of pre and post workover. Testing results show there is no impairment in productivity of the reservoir, which is avoided in workover process by isolating reservoir section. This paper summarizes the completion design process, selection criteria, challenges, and lessons learnt during design and execution phases. This technique will provide the guidelines for installation of the Production string/ESP in hydraulically fractured reservoir without productivity impairment. Novel/Additive Information With modified design, the reservoir is isolated from wellbore and completion with ESP is run successfully without killing reservoir section. Underbalance conditions are achieved prior to establishing communication between reservoir and wellbore.

Integrated Workflow with Experimentation, Modeling, and Field Studies Enhances Fracture Diversion Design in Carbonate Reservoirs

Multiple near-wellbore diverters and their applications exist in the industry. However, understanding of their effectiveness in carbonate acid fracturing applications still has unanswered questions, mainly due to the lack of knowledge on how the fracture width develops at entry points with continuous acid dissolution. This continuum needs to be understood through integrated modeling and experimentation at the yard-scale, and field-scale perspectives. An advanced numerical model was used to analyze the width development in varying calcite/dolomite fractions and acid concentrations. A robust diversion pill was developed during extensive testing, and its performance was validated in the laboratory using a slot test. The goal was to create a system with reliable bridging ability and low permeability to ensure isolation. Multimodal particles help to ensure effective bridging and plug stability. A similar bridging test was conducted at the yard scale with a small pump and low-pressure line setup leading to an 8-mm inside diameter pipe. Results from the laboratory were validated in the yard test to see parameters affecting the bridging. Finally, a well-specific robust workflow was constructed for diversion pill design. Modeling done on a high-resolution fracture hydrodynamics and in-situ kinetics model showed that width development in different scenarios varied from 1.5 to 3.0 mm. Laboratory testing was performed in 0.31- to 063-inch width rectangular slots to normalize the flow rate/area of the cross section, and the plug experienced pressure up to 1,200 psi for several hours at temperatures from 115 to 205°F. No extrusion was observed during the test, which is a valid indicator of plug stability. Sensitivity to flow conditions and carrier fluid properties were estimated. The diversion slurry was mixed in a 0.5 wt% solution of guar gum and displaced at pump rates 100 to 999 ml/min. A yard test was designed to see the bridging of the pill at various concentrations of 75 to 300 lbm/1,000 gal and rates of 0.5 to 3 gal/min. All the laboratory- and yard-scale experimental findings were combined with field case studies to understand fracture bridging for dynamic diversion applications. A workflow using modeling and advanced volumetrics design was devised to enhance the diversion success in field applications. This led to formulating a parametric design measure β, which showed direct correlation and effectiveness on the diversion process. This study gives a 360° solution-based understanding of diversion physics. The proposed combination of mechanical and chemical diversion is a cost-effective method for multistage fracturing. Current comprehensive research involving digitized cores and advanced modeling has significant potential to make this a reliable method to develop tight carbonate formations around the globe.