Evaluating the Performance of Horizontal Multi-Frac Wells in a Depleted Gas Condensate Reservoir in Sultanate of Oman

The Saih Rawl gas condensate field has been producing for 20 years from multiple fractured vertical wells covering a very thick gross interval with varying reservoir permeability. After many years of production, the remaining reserves are mainly in the lowest permeability upper units. A pilot program using horizontal multi-frac wells was started in 2015, and five wells were drilled, stimulated and tested over a four-year period. The number of stages per horizontal well ranged from 6 to 14, but in all cases production was much less than expected based on the number of stages and the production from offset vertical wells producing from the same reservoir units with a single fracture. The scope of this paper is to describe the work that was performed to understand the reason for the lower than expected performance of the horizontal wells, how to improve the performance, and the implementation of those ideas in two additional horizontal wells completed in 2020. The study workflow was to perform an integrated analysis of fracturing, production and well test data, in order to history match all available data with a consistent reservoir description (permeability and fracture properties). Fracturing data included diagnostic injections (breakdown, step-rate test and minifrac) and main fracture treatments, where net pressure matching was performed. After closure analysis (ACA) was not possible in most cases due to low reservoir pressure and absence of downhole gauges. Post-fracture well test and production matching was performed using 3D reservoir simulation models including local grid refinement to capture fracture dimensions and conductivity. Based on simulation results, the effective propped fracture half-length seen in the post-frac production was extremely small, on the order of tens of meters, in some of the wells. In other wells, the effective fracture half-length was consistent with the created propped half-length, but the fracture conductivity was extremely small (finite conductivity fracture). The problems with the propped fractures appear to be related to a combination of poor proppant pack cleanup, low proppant concentration and small proppant diameter, compounded by low reservoir pressure which has a negative impact on proppant regained permeability after fracturing with crosslinked gel. Key conclusions from this study are that 1) using the same fracture design in a horizontal well with transverse fractures will not give the same result as in a vertical well in the same reservoir, 2) the effect of depletion on proppant pack cleanup in high temperature tight gas reservoirs appears to be very strong, requiring an adjustment in fracture design and proppant selection to achieve reasonable fracture conductivity, and 3) achieving sufficient effective propped length and height is key to economic production.

Impact of Delayed Flowback on Well Performance: Case Study

Due to a resource optimization and efficiency improvements, wells that are hydraulically fractured in the tight gas Barik Formation of the Khazzan Field in the Sultanate of Oman are often temporarily left shut-in directly following a large scale massive hydraulic fracturing stimulation treatment. Extensive industry literature has often suggested (and reported), that this may result in a significant direct loss of productivity due to the delayed flowback and the resulting fracture conductivity and formation damage. This paper will review the available data from the Khazzan Field address these concerns; indicating where the concerns should and should not necessarily apply. The Barik Formation in the Khazzan Field is an over-pressured gas-condensate reservoir at 4,500 m with gas permeability ranging from 0.1 to 20 mD. The average well after hydraulic fracturing produces 25 MMscfd and 500 bcpd against a wellhead pressure of 4,000 psi. A typical hydraulic fracturing stimulation treatment consists of 14,000 bbl of a borate-crosslinked guar fluid, placing upwards of 1MM Lbs of high conductivity bauxite proppant within a single fracture. In order to assess the potential production loss due to delayed flowback operations, BP Oman performed a suite of formation damage tests including core samples from the Barik reservoir, fracture conductivity considerations and dynamic behaviors. Additionally, normalized production was compared between offset wells that were cleaned-up and put onto production at different times after the hydraulic fracturing operations. Core tests showed a range of fracture conductivities over time with delayed flowback after using the breaker concentrations from actual treatments. As expected, enhanced conductivity was achieved with additional breaker. The magnitude of the conductivity being created in these massive treatments was also demonstrated to be dominant with respect to damage effects. Finally, a normalized comparison of an extensive suite of wells clearly showed no discernible loss of production resulted from any delay in the flowback operations. This paper describes in details the workflow and resulting analysis of the impact of extensive shut-in versus immediate flowback post massive hydraulic fracturing. It indicates that the impact of such events will be limited if the appropriate steps have been taken to minimize the opportunity for damage to occur. Whereas the existing fracturing literature takes the safe stance of indicating that damage will always result from such shut-ins, this paper will demonstrate the limitations of such assumptions and the flexibility that can be demonstrated with real data.

Development of Tight Upper Cretaceous Reservoir in Offshore Black Sea Adds Life to a Mature Asset

This Upper Cretaceous reservoir, a tight reservoir dominated by silt, marl, argillaceous limestone and conglomerates in Black Sea Histria block, is the dominant of three oil-producing reservoirs in Histria Block. The other two, Albian and Eocene, are depleted, and not the focus of field re-development. This paper addresses the challenges and opportunities that were faced during the re-development process in this reservoir such as depletion, low productivity areas, lithology, seismic resolution, and stimulation effectiveness. Historically, production from Upper Cretaceous wells could not justify the economic life of the asset. As new fracturing technology evolved in recent years, the re-development focused on replacing old, vertical/deviated one-stage stimulations low producing wells with horizontal, multi-stage hydraulic fractured wells. The project team integrated various disciplines and approaches by re-processing old seismic to improve resolution and signal, integrating sedimentology studies using cores, XRF, XRD and thin section analysis with petrophysical evaluation and quantitative geophysical analyses, which then will provide properties for geological and geomechanical models to optimize well planning and fracture placement. Seven wells drilled since end of 2017 to mid-2021 have demonstrated the value of integration and proper planning in development of a mature field with existing depletion. Optimizing the well and fracture placement with respect to depletion in existing wells resulted in accessing areas with original reservoir pressure, not effectively drained by old wells. Integrating the well production performance with tracer results from each fractured stage, and NMR/Acoustic images from logs enhanced the understanding of the impact of lithofacies on stimulation. This has allowed better assessment and prediction of well performance, ultimately improving well placement and stimulation design. The example from this paper highlights the value of the integrating seismic reprocessing, attribute analysis, production technology, sedimentology, cuttings analysis and quantitative rock physics in characterizing the heterogeneity of the reservoir, which ultimately contributed to "sweet spot" targeting in a depleted reservoir with existing producers and deeper understanding of the development potential in Upper Cretaceous. The 2017-2021 wells contribute to more than 30 percent of the total oil production in the asset and reverse the decline in oil production. In addition, these wells have two to four times higher initial rates because of larger effective drainage area than a single fracture well. Three areas of novelty are highlighted in this paper. The application of acoustic image/NMR logging to identify lithofacies and optimize fracturing strategy in horizontal laterals. The tracers analysis of hydraulic fracture performance and integration with seismic and petrophysical analysis to categorize the productivity with rock types. The optimization of fracture placement considering the changes of fluid and proppant volumes without compromising fracture geometries and avoiding negative fracture driven interactions by customized pumping approach.

First Successful Pilot Testing of Unconventional Reservoir in North Kuwait from Scratch to Productivity

Jurassic's kerogen shale-carbonate reservoir in North Kuwait is categorized as a source rock exhibiting micro- to Nano Darcy permeability and is Kuwait Oil Company's focus in recent years. Although the challenges are significant (formation creep, fracturing initiation, etc.), the efforts toward producing from unconventional reservoirs and applying experience from both USA and Canada in this field are ongoing. As a step toward development, the gas field development group selected a vertical pilot well to measure the inflow of hydrocarbon from a single fracture while minimizing formation creep (flowing of particulate material and formation into the wellbore that blocks the production). This step was required prior to drilling a long horizontal lateral wells and completing it with multiple hydraulic fractures to confirm commercial production. A comprehensive design process was executed with the full integration of operator and service company competencies to achieve the three main objectives: First, characterize the kerogen rock mechanics which allows selection of the most competent kerogen beds to prevent collapse of the hole during fracturing (creep effect) by conducting scratch, unconfined stress, proppant embedment, and fluid compatibility tests. Then, prepare a suit of strength measurements on full core samples to help in fracturing design and minimize creep effect. The second objective was to design and implement a robust proppant fracturing program that avoids the kerogen concerns after selecting the most competent reservoir unit and suitable proppant type. Third, perform controlled flowback to unload the well and attempt to establish clean inflow unlike previous attempts that failed to either suitably stimulate or prevent solids production (deliver clean inflow). After analyzing the lab test results, choosing the optimal fracturing design, and preparing the vertical well for proppant hydraulic fracturing, the treatment was performed. In December 2019, the hydraulic fracturing treatment with resin-coated bauxite proppant was successfully pumped through 6 ft of perforation interval and followed by a controlled flowback. Resin-coated bauxite proppant was specifically selected to overcome the creep and embedment effects during the fracture closure and flowback. Moreover, a properly designed choke schedule was implemented to balance unloading with a delicate enough drawdown to avoid formation failure. This paper discusses in detail the lab testing, evolution of fracturing design, treatment analysis, and the robust workflow that led to successfully achieving all main objectives, paving the way for long horizontal lateral wells. This unconventional undertaking in Kuwait presents a real challenge. It is a departure from traditional methods, yet it points toward a high upside potential should the appraisal campaign be completed effectively.

Successful Zonal Isolation in Complex Fractured Carbonate Scenario Using Thixotropic Gel and Hybrid Electric-Fiber Cable Coiled Tubing Technology

Water production has always afflicted mature fields due to the uneconomical nature of high water cut (WC) wells and the high cost of water management. Rigless coiled tubing (CT) interventions with increasingly articulated operating procedures are the key to a successful water reduction. In the scenario presented in this paper, high technological through tubing water shut off (WSO) for a long horizontal open hole (OH) well in a naturally fractured carbonate reservoir leads the way to new opportunities of production optimization. Engineering phase included sealant fluid re-design: the peculiar well architecture and fracture systems led to the customization of a sealant gel by modifying its rheological properties through laboratory tests, to improve effectiveness of worksite operations. A new ad-hoc procedure was defined, with a new selective pumping and testing technique tailored to each drain fracture. The use of Real-Time Hybrid Coiled Tubing Services (CT with fiber optic system coupled with real time capabilities of an electric cable) made it possible to optimize intervention reliability. Details of the operating procedure are given, with the aim of ensuring a successful outcome of the overall treatment Sealing gels are effective in plugging the formation, but in fractured environments the risk of losing the product before it starts to build viscosity is high. The success of the water shut off job has been obtained by using specific gel with thixotropic properties for an effective placement. In addition, the pumping has been performed in steps, each followed by a pressure test to assess the effectiveness of the plugging. Results are compared to two past interventions with equal scope in the same well: a first one with high volume of gel and an unoptimized pumping technique through CT and a second where a water reactive product was pumped by bullheading. The selective and repetitive approach pumping multiple batches of sealant system with CT stationary in front of a single fracture provided the best results from all three techniques. The real-time bottom hole data reading capability provided by hybrid CT allowed the placement of thru tubing bridge plugs (BP) with high accuracy and confidence with the ability to set electrically, therefore reducing risks related to hydraulic setting tools (i.e. premature setting). This also allows continual pumping during the run in hole (RIH) to clean up the zone prior to setting the BP. The combination of this innovative pumping technique and customization of the sealant fluid made it possible to achieve unprecedented water reduction in the field. The high technology CT supported the operation by providing continuous power and telemetry to the bottom hole assembly (BHA) for real time (RT) downhole diagnostics. Moreover, the operating procedures offer basic guidelines to successfully perform water shut off jobs in any other reservoir independent of its geological nature and structure.

The Optimization of Infill Well Fracturing Using an Integrated Numerical Simulation Method of Fracturing and Production Processes

New wells are continuously drilled to improve the recovery of shale gas reservoirs. Production processes of parent wells will induce stress changes in the reservoir and then affect infill wells’ fracturing design. In this paper, we employed an integrated numerical method to simulate the hydraulic fracturing and production processes with single one method, thus the fracturing scheme of the infill well can be optimized. The integrated numerical method is based on the finite element method (FEM), which is named as the discontinuous discrete fracture method (DDFM). The DDFM can be used with conventional finite element mesh, which is perfectly compatible with the discrete fracture model (DFM). The fully coupled solution of DDFM is validated by two problems, including Mandel problem's analytical solution and the numerical solutions of the single fracture propagation. When predict the shale gas production, a new diffusion equation is modified to describe the shale gas flow, and the simulation results showed a good agreement with the field data. At last, this paper takes an infill well construction in a shale gas reservoir in south China as an example. The hydraulic fractures of parent wells are interpreted from micro-seismic data and described with DFM to reduce the computational cost. Then the infill well's hydraulic fractures are described using DDFM. After simulating the production process of two parent wells, we get the current formation pressure and stress state. Aims at obtaining the maximum profit of the whole well region, by comparing the gas production of different fracturing schemes, we can choose the optimal fracturing scheme of the infill well.

The Evolution of Olecranon Fractures and Its Fixation Strategies

Introduction. Olecranon fractures are a common fracture of the upper extremity. The primary aim was to investigate the evolution of olecranon fractures and fixation method over a period of 12 years. The secondary aim was to compare complication rates of Tension Band Wiring (TBW) and Plate Fixation (PF). Materials and Methods Retrospective Study for all patients with surgically treated olecranon fractures from 1 January 2005 to 31 December 2016 from a tertiary trauma center. Records review for demographic, injury characteristics, radiographic classification and configuration, implant choices and complications. Results grouped into three 4-year intervals, analyzed comparatively to establish significant trends over 12 years. Results 262 patients were identified. Demographically, increasing mean age (48.7 to 58.9 years old, p-value 0.004) and higher ASA scores (7.1% ASA 3 to 21.0% ASA 3 p-value 0.001). Later fractures were more oblique (fracture angle 86.1 to 100.0 degrees, p-value 0.001) and comminuted (Schatzker D type 10.4–30.0%, p-value 0.025, single fracture line 94.0–66.0%, p-value 0.001). Implant choice, sharp increase in PF compared to TBW (PF 16.0% to PF 80.2%, p-value 0.001). Complication-wise, TBW had higher rates of symptomatic implant, implant and bony failures and implant removal. Conclusion Demographic and fracture characteristic trends suggest that olecranon fractures are exhibiting fragility fracture characteristics (older age, higher ASA scores, more unstable, oblique and comminuted olecranon fractures). Having a high index of suspicion would alert surgeons to consider use of advanced imaging, utilize appropriate fixation techniques and manage the underlying osteoporosis for secondary fracture prevention. Despite this, trends suggest a potential overutilization of PF particularly for stable fracture patterns and the necessary precaution should be exercised.

Evaluation Method of the Vertical Well Hydraulic Fracturing Effect Based on Production Data

Hydraulic fracturing technology has become a key technology for the development of low-permeability/tight oil and gas reservoirs. The evaluation on the postfracturing effect is imperative to the formulation and implementation of the fracturing and development plan. Based on the characteristics of the flow in fracture network after a large-scale hydraulic fracturing, a numerical method for evaluating the effect of fracturing in vertical well was established. This study conducts postfracturing effect evaluations to block C Oilfield’s wells that underwent conventional fracturing and volumetric fracturing, respectively, proposes the definition of fracture network conductivity and its relationship with cumulative production, and analyzes the fracturing construction parameters. The results suggest that the conventional fracturing can only form a single fracture instead of a stimulated reservoir volume (SRV) region. However, the volumetric fracturing transformation can form a complex fracture network system and SRV region and meanwhile bring obvious increase in the production. The effective time lasts for a longer period, and the increase of average daily oil is 2.2 times more than that of conventional fracturing. Additionally, with the progress of the production, the SRV area within the core region of the volume transformation gradually decreased from 6664.84 m2 to 4414.45 m2; the SRV area of the outer region decreased from 7913.5 m2 to 5391.3 m2. As the progress develops, the equivalent permeability and the area of the fracture gradually decrease as the fracturing effect gradually weakens, and so does the conductivity of the network decreasing exponentially; a good correlation is observed between the conductivity of the fracture network, the cumulative production, and fracturing construction parameters, which can serve as the evaluation parameters for the fracturing effects and the basis for fracturing productivity prediction and provide a guidance for fracturing optimization design.

A Cut-Cell Polyhedral Finite Element Model for Coupled Fluid Flow and Mechanics in Fractured Reservoirs

Mechanical deformation induced by injection and withdrawal of fluids from the subsurface can significantly alter the flow paths in naturally fractured reservoirs. Modeling coupled fluid-flow and mechanical deformation in fractured reservoirs relies on either sophisticated gridding techniques, or enhancing the variables (degrees-of-freedom) that represent the physics in order to describe the behavior of fractured formation accurately. The objective of this study is to develop a spatial discretization scheme that cuts the "matrix" grid with fracture planes and utilizes traditional formulations for fluid flow and geomechanics. The flow model uses the standard low-order finite-volume method with the Compartmental Embedded fracture Model (cEDFM). Due to the presence of non-standard polyhedra in the grid after cutting/splitting, we utilize numerical harmonic shape functions within a Polyhedral finite-element (PFE) formulation for mechanical deformation. In order to enforce fracture-contact constraints, we use a penalty approach. We provide a series of comparisons between the approach that uses conforming Unstructured grids and a Discrete Fracture Model (Unstructured DFM) with the new cut-cell PFE formulation. The manuscript analyzes the convergence of both methods for linear elastic, single-fracture slip, and Mandel’s problems with tetrahedral, Cartesian, and PEBI-grids. Finally, the paper presents a fully-coupled 3D simulation with multiple inclined intersecting faults activated in shear by fluid injection, which caused an increase in effective reservoir permeability. Our approach allows for great reduction in the complexity of the (gridded) model construction while retaining the solution accuracy together with great saving in the computational cost compared with UDFM. The flexibility of our model with respect to the types of grid polyhedra allows us to eliminate mesh artifacts in the solution of the transport equations typically observed when using tetrahedral grids and two-point flux approximation.