Workflow to Optimize Cluster Spacing Design of Horizontal Multistage Fractured Well in Unconventional Source Rock

Horizontal drilling and multistage hydraulic fracturing applied in unconventional reservoirs over the past decade to create a large fracture surface area to improve the well productivity. The combination of reservoir quality with perforation cluster spacing and fracture staging are keys to successful hydraulic fracturing treatment for horizontal wells. The objective of this work is to build and calibrate a dynamic model by integrating geologic, hydraulic fracture, and reservoir modeling to optimize the number of clusters and other completion parameters for a horizontal well drilled in the source rock reservoir using simulation and analytical models. The methodology adopted in this study covers the integration of geological, petrophysical, and production data analysis to evaluate reservoir and completion qualities and quantify the heterogeneity and the perforation clusters number required within a frac stage. Assuming all perforation clusters are uniformly distributed within a stage. The hydraulic planer fracture attributes assumed and the surface production measurement together with the production profile were used to calibrate the reservoir model. The properties of the Stimulated Reservoir Volume "SRV" were defined after the final calibration using reservoir model including hydraulic fractures. The calibrated reservoir model was used to carry out sensitivity analyses for cluster spacing optimization and other completion parameters considering the surface and reservoir constraints. An optimum cluster spacing was observed based on the Estimated Ultimate Recovery "EUR" of the subject well by reservoir properties. The final results based on 70% of perforation clusters contribution to production observed from PLT log, and the results of this study were implemented. Afterwards, another study has been undertaken to increasing the stimulation effectiveness and maximizing the number of perforation clusters contributing to productivity as an area for improvement to engineering the completion design. The methodology adopted in this study identifies the most important parameters of completion affecting well productivity for specific unconventional reservoirs. This study will help to engineer completion design, improve cluster efficiency, reduce cost and increase well EUR for the development phase.

A Modeling Study of the Productivity of Horizontal Wells in Hydrocarbon-Bearing Reservoirs: Effects of Fracturing Interference

Commercial production from hydrocarbon-bearing reservoirs with low permeability usually requires the use of horizontal well and hydraulic fracturing for the improvement of the fluid diffusivity in the matrix. The hydraulic fracturing process involves the injection of viscous fluid for fracture initiation and propagation, which alters the poroelastic behaviors in the formation and causes fracturing interference. Previous modeling studies usually focused on the effect of fracturing interference on the multicluster fracture geometry, while the related productivity of horizontal wells is not well studied. This study presents a modeling workflow that utilizes abundant field data including petrophysical, geomechanical, and hydraulic fracturing data. It is used for the quantification of fracturing interference and its correlation with horizontal well productivity. It involves finite element and finite difference methods in the numeralization of the fracture propagation mechanism and porous media flow problems. Planar multistage fractures and their resultant horizontal productivity are quantified through the modeling workflow. Results show that the smaller numbers of clusters per stage, closer stage spacings, and lower fracturing fluid injection rates facilitate even growth of fractures in clusters and stages and reduce fracturing interference. Fracturing modeling results are generally correlated with productivity modeling results, while scenarios with stronger fracturing interference and greater stimulation volume/area can still yield better productivity. This study establishes the quantitative correlation between fracturing interference and horizontal well productivity. It provides insights into the prediction of horizontal well productivity based on fracturing design parameters.

Modified Horizontal Well Productivity Model for a Tight Gas Reservoir Subjected to Non-Uniform Damage and Turbulence

Tight gas reservoirs are finding greater interest with the advancement of technology and realistic prediction of flow rate and pressure from such wells are critical in project economics. This paper presents a modified productivity equation for tight gas horizontal wells by modifying the mechanical skin factor to account for non-uniform formation damage along with the incorporation of turbulence effect in the near-wellbore region. Hawkin’s formula for calculating skin factor considers the radius of damage as a constant value, which is less accurate in low-permeability tight gas reservoirs. This paper uses a multi-segment horizontal well approach to develop the local skin factors and the equivalent skin factor by equating the total production from the entire horizontal well to the sum of the flow from individual segmented damaged zones along the well length. Conical and horn-shaped damaged profiles are used to develop the equivalent skin used in the horizontal well productivity equation. The productivity model is applied to a case study involving the development of a tight gas field with horizontal wells. The influence of the horizontal well length, damaged zone permeability, drainage area, reservoir thickness, and wellbore diameter on the calculated equivalent skin (of a non-uniform skin distribution) and the flow rate (with turbulence and no turbulence) are investigated. The results obtained from this investigation show significant potential to assist in making practical decisions on the favorable parameters for the success of the field development in terms of equivalent skin factor, flow rate, and inflow performance relationships (IPR).

Advanced Well Completion Strategies to Improve Gas Production Deliverability in Marginal Tight Gas Reservoirs from an Onshore Abu Dhabi Gas Field

Reservoir X is a marginal tight gas condensate reservoir located in Abu Dhabi with permeability of less than 0.05 mD. The field was conventionally developed with a few single horizontal wells, though sharp production decline was observed due to rapid pressure depletion. This study investigates the impact of converting the existing single horizontal wells into single long horizontal, dual laterals, triple laterals, fishbone design and hydraulic fracturing in improving well productivity. The existing wells design modifications were planned using a near reservoir simulator. The study evaluated the impact of length, trajectory, number of laterals and perforation intervals. For Single, dual, and triple lateral wells, additional simulation study with hydraulic fracturing was carried out. To evaluate and obtain effective comparisons, sector models with LGR was built to improve the simulation accuracy in areas near the wellbore. The study conducted a detailed investigation into the impact of various well designs on the well productivity. It was observed that maximizing the reservoir contact and targeting areas with high gas saturation led to significant increase in the well productivity. The simulation results revealed that longer laterals led to higher gas production rates. Dual lateral wells showed improved productivity when compared to single lateral wells. This incremental gain in the production was attributed to increased contact with the reservoir. The triple lateral well design yielded higher productivity compared to single and dual lateral wells. Hydraulic fracturing for single, dual, and triple lateral wells showed significant improvement in the gas production rates and reduced condensate banking near the wellbore. A detailed investigation into the fishbone design was carried out, this involved running sensitivity runs by varying the number of branches. Fishbone design showed considerable increment in production when compared to other well designs This paper demonstrates that increasing the reservoir contact and targeting specific areas of the reservoir with high gas saturation can lead to significant increase in the well productivity. The study also reveals that having longer and multiple laterals in the well leads to higher production rates. Hydraulic fracturing led to higher production gains. Fishbone well design with its multiple branches showed the most production again when compared to other well designs.

Restoring Well Productivity Through a Fit-for-Purpose Sludge Cleanout Job

Sludge formation could significantly impair well productivity if deposited in the wellbore or surface flow lines. In a field where sludge formation is not common, an oil production well showed a sudden deterioration in well productivity. Thorough investigation of abnormal well performance, from surface and sub-surface perspective, indicated that the deposition of a thick layer of a tight emulsion across the surface choke has resulted in ceasing the oil flow to the gas oil separation plant. Extensive lab analysis indicated that the obstruction material was a sludge deposition promoted by the presence of asphaltene, high amount of iron and low pH brine. It is noteworthy to mention that the analytical results of lab prepared emulsion samples elucidate the rule of low pH aqueous solution, asphaltene and iron ions in inducing tight emulsion formation which helps to understand the root causes of sludge deposition. To come up with a cost-effective remedial treatment considering health, safety and environment (HSE), different emulsion breaking formulations, including different de-emulsifiers and anti-sludge agents, were examined in this study. An effective diesel-based formulation including proper de-emulsifier and anti-sludging agent was used during the execution of the field job. The design of the field job took into consideration a minimal footprint to the environment through the flowback of the well to the neighboring gas oil separation plant. This paper summarizes the joint efforts by production engineers and lab scientists to systemically tackle such major flow assurance issues which could significantly jeopardize wells productivity. The systemic approach starts with problem detection through well intervention and sample collection. It also includes the lab work which was carried out to identify the type and composition of deposition and evaluate/optimize a proper formulation for sludge deposition removal. The paper discusses in detail the design and execution of a successful field treatment, which has resulted in restoring and maintaining the well potential.

Paradigm Shift from Cemented Completions to Multi-Stage Completion Strategy for Managing Tight Gas Development Challenges

The development of North Kuwait Jurassic gas assets has strategic importance for Kuwait's production strategy as the only non-associated gas-producing field in Kuwait. This paper demonstrates the benefits, challenges and lessons learned of the recent paradigm shift in Jurassic tight gas wells’ completion strategy from cemented liner to multi-stage completion. Successful expansion of Multi-Stage Completion (MSC) technology is achieved at the field level led by the integrated team efforts in 2020/21, despite challenging constraints of COVID-19. MSC's help to enhance overall well production potential, overcome reservoir and intervention operation challenges, and allow early production delivery, which is a key factor to achieve a strategic asset production target of 70-80% by 2024/25. Many technical and logistic challenges were experienced during first installations of which the relevant learnings will be shared in this paper. The Jurassic gas asset produces mainly from deep high pressure and temperature, conventional and unconventional tight carbonate reservoirs. The recovery from such complex heterogeneous reservoirs is extremely challenging if conventional development strategies are applied. Therefore, a dedicated full development plan applying integrated upstream and downstream technologies is important to achieve the strategic production target. Due to the excessive Jurassic carbonate reservoir tightness, permeability contrast and dual permeability effect (matrix and natural fractures), well productivity potential significantly depends on the effectiveness of subsequent stimulation treatments of such complex heterogeneous reservoirs to improve well productivity and potentially connect with natural fractures. Selecting proper well completion design is critical to overcome such reservoir challenges and ensure effective acid stimulation treatments for the mix of conventional and unconventional formations that need convenient diversion mechanism during stimulation to enhance the productivity of each individual reservoir flow unit and enable selective future flexibility of re-stimulation and reservoir management. The asset team has recently applied a step change in completion strategy to open hole multi-stage ball drop completions using state of the art MSC technologies including closeable frac sleeves, full 3.5-in monobore ID post frac sleeves milling and debris sub enclosure to protect the MSC string during casing tie-back operations. This is to overcome reservoir complexity, eliminate wellbore cleaning and decrease the challenges and risks that accompany multiple perforation intervention operations. As well as, eliminate cement quality risks and uncertainties, improve overall cost, and fast track well delivery to production to meet asset production targets by significantly reducing operation time from approximately one month for plug and perf techniques to less than one week when using continuous and less subsurface intervention operations. Recently, a total of 13 new MSC installations and subsequent multi-stage stimulations were achieved in seven months, fromQ3-2020 to Q1-2021, with positive overall production results, significant improvement of intervention operation efficiency and faster well delivery to production. This paper will describe the details of progress to date, and the plan forward for optimization and new technology trials to further improve well performance.

A Holistic Study on Performance Evaluation of Horizontal Wells and its Implications on Tight Spacing Drilling Strategy in Mauddud Reservoir

The objective of this paper is to present the comparative results of comprehensive analysis of horizontal well productivity and completion performance with vertical wells drilled and completed within same time window in the Mauddud reservoir in the Bahrain Oil Field. The study also focuses on performance evaluation of horizontal wells drilled in different areas of the field. Key reservoir risks and uncertainties associated with horizontal wells are identified, and contingency and mitigation plans are devised to address them. Besides controlling gas production, the benefits of using cemented horizontal wells over vertical wells are highlighted based on performance of recently completed workovers and economic evaluation. Reservoir and well performance are analyzed using a variety of analytical techniques such as well productivity index (PI), productivity improvement factor (PIF), normalized productivity improvement factor (PIFn), well productivity coefficient (Cwp), in conjunction with a statistical distribution function to reflect the average and most likely values. In addition, average oil/gas/water production, cumulative production, reserves, and estimated ultimate recovery (EUR) are compared for both vertical and horizontal wells using decline curve analysis. Furthermore, economics are evaluated for tight spacing drilling with vertical wells, as well as horizontal cemented wells, to optimize future development of Mauddud reservoir. Based on the evaluation, it is inferred that the average horizontal well outperforms a vertical well in terms of production rate, PI, PIF, reserves, and EUR in the field except in waterflood areas. Based on average cumulative oil, reserves and EUR, and well productivity coefficient, overall performance of horizontal wells are better in the GI area in comparison their counterparts in the North/South areas of the Mauddud reservoir, where the dominant mechanism is strong water drive. High gas and water production in horizontal wells are attributed to open-hole completions of the wells and the possibility of poor cementing. A trial has been completed recently in a few horizontal wells using cased-hole cemented completion with selected perforations, resulting in improved oil rates and the drastic reduction of gas to oil ratio. Furthermore, two new cased-hole cemented horizontal wells are planned in 2021 as a trial. A detailed cost-benefit analysis using a net present value concept is performed, leading to a rethink of future development strategies with a mix of both vertical as well as horizontal wells in the GI area. Using the dimensionless correlations and distribution functions, the productivity and PIF of new horizontal wells to be drilled in any area can be predicted during early prognosis given the values of average reservoir permeability, well length, and fluid properties. This study can be used as a benchmark for the development of a thin oil column with a large and expanding gas cap under crestal gas injection using both vertical and horizontal wells.

Factors influencing gas well productivity in fractured tight sandstone reservoir

There are many factors which influence the absolute open flow potential (AOFP) of gas well. One of them is the angle between maximum principal stress direction and natural fracture strike in gas reservoir. In order to find out how the angle influences the AOFP of gas well. A lot of data related to gas well productivity of 14 wells located in gas reservoir T were collected and collated. Influential intensity of each factor on the AOFP before and after reservoir modification was investigated through grey relation analysis method. Results indicated that the AOFP of gas well before and after reservoir modification was governed by 10 factors. The five central factors influencing the initial AOFP are natural fracture density, porosity, permeability, elevation of geological top surface, and gas saturation, respectively. The five central factors influencing the AOFP of hydraulically fractured gas well are porosity, gas saturation, elevation of geological top surface, minimum principal stress, and permeability, respectively. Angle between maximum principal stress direction and natural fracture strike was not the central factor influencing gas well productivity. Reservoir modification can greatly improve gas well productivity in fractured tight sandstone reservoir. Natural fracture density was the strongest influencing factor of the initial AOFP. Minimum principal stress was one of the central factors influencing the AOFP of hydraulically fractured gas well. Research results can be used to guide well deployment and gas productivity investment projects of fractured tight sandstone reservoir.

Semi-Analytical Rate Decline Solutions for a Refractured Horizontal Well Intercepted by Multiple Reorientation Fractures with Fracture Face Damage in an Anisotropic Tight Reservoir

Refracturing treatment is an economical way to improve the productivity of poorly or damaged fractured horizontal wells in tight reservoirs. Fracture reorientation and fracture face damage may occur during refracturing treatment. At present, there is still no report on the rate decline solution for refractured horizontal wells in tight reservoirs. In this work, by taking a semi-analytical method, traditional rate decline and Blasingame-type rate decline solutions were derived for a refractured horizontal well intercepted by multiple reorientation fractures with fracture face damage in an anisotropic tight reservoir. The accuracy and reliability of the traditional rate decline solution were verified and validated by comparing it with a classic case in the literature and a numerical simulation case. The effects of fracture reorientation and fracture face damage on the rate decline were investigated in depth. These investigations demonstrate that fracture face damage is not conducive to increasing well productivity during the early flow period and there is an optimal matching relationship between the principal fracture section angle and permeability anisotropy, particularly for the reservoirs with strong permeability anisotropy. The fracture length ratio and fracture spacing have a weak effect on the production rate and cumulative production while the fracture number shows a strong influence on the rate decline. Furthermore, multifactor sensitivity analysis indicates that fracture conductivity has a more sensitive effect on well productivity than fracture face damage, implying the importance of improving fracture conductivity. Finally, a series of Blasingame-type rate decline curves were presented, and type curve fitting and parameter estimations for a field case were conducted too. This work deepens our understanding of the production performance of refractured horizontal wells, which helps to identify reorientation fracture properties and evaluate post-fracturing performance.