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Abstract For as long as we have been performing hydraulic fracturing, we have been trying to ensure that we stay out of undesirable horizons, potentially containing water and/or gas. The holy grail of hydraulic fracturing, an absolute control of created fracture height, has eluded the industry for more than 70 years. Of course, there have been many that have claimed solutions, but all the marketed approaches have at best merely created a delay to the inevitable growth and at worst been a snake-oil approach with little actual merit. Fundamentally, the applied techniques have attempted to delay or influence the underlying equations of net-pressure and stress variation; but having to ultimately honour them and by doing so then condemned themselves to limited success or outright failure. Fast forward to 2020, and a reassessment of the relative importance of height-growth constraint and what may have changed to help us achieve this. The development of unconventionals are focused on creating as much surface area as possible in micro/nano-Darcy environments, across almost any phase, but with typically poor line of sight to profit. However, the more valuable business of conventional oil and gas is working in thinner and thinner reservoirs with an often-deteriorating permeability, but with a significantly higher potential economic return. What unconventional has successfully delivered however, is a rapid deployment and acceleration in a range of completion technologies that were unavailable just a few years ago. We will demonstrate that these technologies potentially offer the capability of finally being able to control fracture height-growth. Consideration of a range of previously applied height-growth approaches will demonstrate how they attempted to fool or fudge height growth creation mechanisms. With this clarity, we can consider what advances in completion technology may offer in terms of delivering height growth control. We suggest that with the technology and approaches that are currently available today, that height-growth control is finally within reach. We will go on to describe a multi-well Pilot program, in deployment and execution in 2020/021 in Western Siberia; where billions of barrels remain to be recovered in thin oil-rim, low permeability sandstone reservoirs below gas or above water. A comprehensive assessment of the myriad of height-growth approaches that have been utilized over the last 70 years was performed, but in each case demonstrated the fallibility and limitations of each of these. However, rather than the interpretation that such control is not achievable, instead we will show a mathematically sound approach, along with field data and evidence that this is possible. The presentation will demonstrate that completion advances over the last 10 - 15 years make this approach a reality in the present day; and that broader field implementation is finally within reach.
Abstract Recent diagnostic fracture injection test (DFIT) data presented on a Bourdet log-log diagnostic plot showed derivative slope of 0 in the before closure (BC) portion of the DFIT response. Some works qualitatively describe it as radial flow. This behavior has not been quantitatively analyzed, modeled and matched. The present work disagrees with the hypothesis of radial flow and successfully matches the relatively flat trend in the Bourdet derivative with a model dominated by friction dissipation coupled with tip extension. The flat trend in Bourdet derivative occurs shortly after shut-in during the before closure period. Because a flat derivative trend suggests diffusive radial flow, our first approach was to consider the possibility that an open crack at a layer interface stopped the fracture propagation and caused the apparent radial flow behavior observed in falloff data. However, a model that coupled pressure falloff from diffusive flow into a layer interface crack with pressure falloff from closure of a fracture that propagated up to the layer interface failed to reproduce the observed response. Subsequently, we discovered that existing models could match the data without considering the layer interface crack. We found that data processing is very important to what is observed in derivative trends and can mislead the behavior diagnosis. We succeeded to match one field DFIT case showing an obvious early flat trend. The presence and dominance of geomechanics, coupled with diffusive flow, disqualify the description of the flat trend in Bourdet derivative as radial flow. Instead, flow friction coupled with tip extension can completely match the observed behavior. Based on our model, cases with a long flat trend have large magnitude near-wellbore tortuosity friction loss and relatively long tip extension distance. Further, we match the near wellbore tortuosity behavior with rate raised to a power lower than the usually assumed 0.5. The significance of these analyses relates to two key factors. First, large magnitude near wellbore tortuosity friction loss increases the pressure required for fracture propagation during pumping. Second, tip extension is a way to dissipate high pumping pressure when very low formation permeability impedes leakoff. Matching transient behavior subject to the presence of both of these factors requires lowering the near-wellbore tortuosity exponent.
Abstract This paper further develops an analysis of proppant distribution patterns in hydraulically fractured wells initially presented in SPE-199693-MS. A significantly enlarged database of in-situ perforation erosion measurements provides a more rigorous statistical basis allowing some previously reported trends to be updated, but the main objective of the paper is to present additional insights identified since the original paper was published. Measurements of the eroded area of individual perforations derived from downhole camera images again provide the input for this study. Entry hole enlargement during limited entry hydraulic fracturing provides strong and direct evidence that proppant was successfully placed into individual perforations. This provides a straightforward evaluation of cluster efficiency. Perhaps more importantly the volume of proppant placed into a perforation can also be inferred from the degree of erosion. Summing individual perforation erosion at cluster level allows patterns and biases to be identified and an understanding of proppant distribution across stages has been developed. Outcomes from an analysis of a database that now exceeds 50,000 eroded perforations are presented. Uniform reservoir stimulation is a key objective of fracture treatments but remains challenging to measure and report. The study therefore focused on understanding how uniformly proppant is distributed across more than 1,800 measured stages. Results demonstrate how proppant distribution within stages is influenced when treatment parameters change. Our approach was to vary one parameter, for example the stage length, while all other parameters were maintained at a consistent value. We investigated multiple parameters that can be readily controlled during treatment design and show how these can be manipulated to improve proppant distribution. These included stage length, cluster spacing, perforation count per cluster and perforation phase. Hydraulic fracturing is a complex, high energy process with numerous input parameters. At individual cluster and stage level outcomes can be unpredictable and diagnostic results are often quite variable. The approach taken here was to complete a statistical analysis of a sufficiently large dataset of in-situ measurements. This allowed common trends and patterns to be confidently identified and conclusions reached on how proppant distribution is affected by varying specific design parameters. This should be of interest and value to those designing hydraulic fracture treatments.
Khan, Abdul Muqtadir (Schlumberger) | BinZiad, Abdullah (Saudi Aramco) | Al Subaii, Abdullah (Saudi Aramco) | Alqarni, Turki (Schlumberger) | Jelassi, Mohamed Yassine (Schlumberger) | Najmi, Asim (Schlumberger)
Abstract Diagnostic pumping techniques are used routinely in proppant fracturing design. The pumping process can be time consuming; however, it yields technical confidence in treatment and productivity optimization. Recent developments in data analytics and machine learning can aid in shortening operational workflows and enhance project economics. Supervised learning was applied to an existing database to streamline the process and affect the design framework. Five classification algorithms were used for this study. The database was constructed through heterogeneous reservoir plays from the injection/falloff outputs. The algorithms used were support vector machine, decision tree, random forest, multinomial, and XGBoost. The number of classes was sensitized to establish a balance between model accuracy and prediction granularity. Fifteen cases were developed for a comprehensive comparison. A complete machine learning framework was constructed to work through each case set along with hyperparameter tuning to maximize accuracy. After the model was finalized, an extensive field validation workflow was deployed. The target outputs selected for the model were crosslinked fluid efficiency, total proppant mass, and maximum proppant concentration. The unsupervised clustering technique with t-SNE algorithm that was used first lacked accuracy. Supervised classification models showed better predictions. Cross-validation techniques showed an increasing trend of prediction accuracy. Feature selection was done using one-variable-at-a-time (OVAT) and a simple feature correlation study. Because the number of features and the dataset size were small, no features were eliminated from the final model building. Accuracy and F1 score calculations were used from the confusion matrix for evaluation, XGBoost showed excellent results with an accuracy of 74 to 95% for the output parameters. Fluid efficiency was categorized into three classes and yielded an accuracy of 96%. Proppant concentration and proppant mass predictions showed 77% and 86% accuracy, respectively, for the six-class case. The combination of high accuracy and fine granularity confirmed the potential application of machine learning models. The ratio of training to testing (holdout) across all cases ranged from 80:20 to 70:30. Model validations were done through an inverse problem of predicting and matching the fracture geometry and treatment pressures from the machine learning model design and the actual net pressure match. The simulations were conducted using advanced multiphysics simulations. The advantages of this innovative design approach showed four areas of improvement: reduction in polymer consumption by 30%, reduction of the flowback time by 25%, reduction of water usage by 30%, and enhanced operational efficiency by 60 to 65%.
Norris, Mark (Oilfield Production Enhancement Consultancy Services Ltd.) | Langford, Marc (Spirit Energy UK) | Giraud, Charlotte (Schlumberger Europe) | Stanley, Reginald (Schlumberger Europe) | Ball, Steve (Oilfield Production Enhancement Consultancy Services Ltd.)
Abstract Hydraulic fracturing has been well established in the Southern North Sea (SNS) since the mid-1980s; however, it has typically been conducted as the final phase of development in new gas fields. One of these fields is Chiswick located in the Greater Markham area 90 miles offshore UK in 130 ft of water. Following an unsuccessful well repair of the multi-fractured horizontal well C4, it was decided to cost-effectively and expediently exploit the remaining pressure-depleted reserves near the toe via a single large fracture initiated from a deviated sidetrack wellbore designated C6. A deviated wellbore was chosen versus the original near-horizontal well to reduce well risk and costs and ultimately deliver an economic well. Several key challenges were identified, and mitigating measures were put in place. Modular formation dynamics tester data from the sidetrack open hole indicated the reservoir pressure gradient had depleted to 0.23 to 0.25 psi/ft, raising concerns about the ability of the well to unload the fluid volumes associated with a large fracture treatment. Wellbore deviation and azimuth with the associated potential for near-wellbore tortuosity would drive a typically short perforation interval (i.e., 3 ft). However, a compromise to mitigate convergent pressure loss in depletion was required, and the perforation interval was therefore set at 14 ft with provision made for robust step-down tests (SDT) and multi-mesh sand slugs. To further offset any near-well convergence pressure drop during cleanup, an aggressive tip screenout (TSO) proppant schedule, including a high concentration tail-in (12 PPA) with an aggressive breaker schedule, was executed to fully develop propped hydraulic width. Following formation breakdown and SDT to 40 bbl/min, the well went on near-instantaneous vacuum. Clearly, an extremely conductive feature had been created or contacted. However, upon use of a robust crosslinked gel formulation and 100-mesh sand, the bottomhole and positive surface pressure data allowed a suitable fracture design to be refined and placed with a large width, as evidenced by the extreme 2,309-psi net pressure development over that of the pad stage while placing 500,500 lbm of 16/30 resin-coated (RC) intermediate strength proppant (ISP) to 12 PPA. Although a lengthy nitrogen lift by coiled tubing (CT) was planned, the well cleanup response in fact allowed unaided hydrocarbon gas flow to surface within a short period. The well was then further beaned-up under well test conditions to a flow rate of approximately 26 MMscf/D under critical flowing conditions with a higher bottomhole flowing pressure than that of the original C4 well. Given the last producing rate of the original multiple fractured horizontal wellbore was 27 MMscf/D at a drawdown of 1,050 psi through two separate hydraulic fractures, then the outcome of this well was judged to be highly successful and at the limit of predrill expectations. This case history explains and details the rationale, methods, and techniques employed in well C6 to address the challenge of successful hydraulic fracture stimulation in a depleted formation. Challenges were addressed by combining a number of techniques, coupled with field experience, resulting in a highly productive well despite the relatively low reservoir pressure coupled with a limited time frame to plan and execute. These techniques are transferrable to other offshore gas fields in the region where reservoir depletion makes economic recovery difficult or indeed prohibitive.
Abstract Efficient multistage hydraulic fracturing in horizontal wells in tight-gas formations with multilayered and laminated reservoirs is a very challenging subject matter; due to formation structure, required well trajectory, and the ability to establish a conductive and permanent connection between all the layers. BP Oman had initiated the technical journey to deliver an effective horizontal well multistage frac design through learnings obtained during three key pilot horizontal wells. Since these initial wells, additional candidates have been drilled and stimulated, resulting in further advancement of the learning curve. Many aspects will be covered in this paper, that will describe how to facilitate the most effective hydraulic fracture placement and production performance, under these laminated conditions. These approaches will include the completion and perforation selection, fracture initiation zone selection, fracture height consideration, frac fluid type and design. The paper will go on to describe a range of different surveillance options, including clean-up and performance surveillance as well as number of other factors. The experiences that have been gained provide valuable insight and learning about how to approach a multistage fracturing horizontal well program in this kind of depositional environment. Additionally, how these lessons can potentially be subsequently adapted and applied to access resources in the more challenging and higher risk areas of the field. For example, this paper will present direct comparison of over and under-displaced stages; differences in execution and production for cased hole and open hole completions; and many other variables that always under discussion for hydraulic fracturing in horizontal wells. This paper describes in detail the results of many multistage fracturing trials by BP Oman in horizontal wells drilled in challenging multilayered and laminated tight-gas reservoirs. These findings may help to cut short learning curve in similar reservoirs in the Middle East Region and elsewhere.
Abstract The Montney reservoir is one of the most prolific unconventional multi-stacked dry and liquid-rich gas plays in North America. The type of fracturing method and fluid has a significant impact on water-phase trapping, casing deformation, and well performance in the Montney. Different fracturing methods (plug and perf/plug and perf with ball/ball and seat/single-entry pinpoint) and fluids (slickwater/hybrid/oil-based/energized/foam) have been tested in 4000 Montney wells to find optimal fracturing method and fluid for different reservoir qualities and fluid windows and to minimize water-phase trapping and casing deformation. The previous studies reviewing the performance of fracturing methods in Montney do not represent a holistic evaluation of these methods, due to some limitations, including: (1) Using a small sample size, (2) Having a limited scope by focusing on a specific aspect of fracturing (method/fluid), (3) Relying on data analytics approaches that offer limited subsurface insight, and (4) Generating misleading results (e.g., on optimum fracturing method/fluid) through using disparate data that are unstructured and untrustworthy due to significant regional variation in true vertical depth (TVD), geological properties, fluid windows, completed lateral length, fracturing method/fluid/date, and drawdown rate management strategy. The present study eliminates these limitations by rigorously clustering the 4000 Montney wells based on the TVD, geological properties, fluid window, completed lateral length, fracturing method/fluid/date, and drawdown strategy. This clustering technique allows for isolating the effect of each fracturing method by comparing each well's production (normalized by proppant tonnage, fluid volume, and completed length) to that of its offsets that use different fracturing methods but possess similar geology and fluid window. With similar TVD and fracturing fluid/date, wells completed with pinpoint fracturing outperform their offsets completed with ball and seat and plug and perf fracturing. However, wells completed with ball and seat and plug and perf methods that outperform their offset pinpoint wells have either: (1) Been fractured 1 to 4 years earlier than pinpoint wells and/or (2) Used energized oil-based fluid, hybrid fluid, and energized slickwater versus slickwater used in pinpoint offsets, suggesting that the water-phase trapping is more severe in these pinpoint wells due to the use of slickwater. Previous studies often favored one specific fracturing method or fluid without highlighting these complex interplays between the type of fracturing method/fluid, completion date (regional depletion), and the reservoir properties and hydrodynamics. This clustering technique shows how proper data structuring in disparate datasets containing thousands of wells with significant variations in geological properties, fluid windows, fracturing method/fluid, regional depletion, and drawdown strategy permits a consistent well performance comparison across a play by isolating the impact of any given parameter (e.g., fracturing methods, depletion) that is deemed more crucial to fracturing design and field development planning.
Shaoul, Josef R. (Fenix Consulting Delft) | Park, Jason (Fenix Consulting Delft) | Boucher, Andrew (Fenix Consulting Delft) | Tkachuk, Inna (Fenix Consulting Delft) | Veeken, Cornelis (Petroleum Development Oman) | Salmi, Suleiman (Petroleum Development Oman) | Bahri, Khalfan (Petroleum Development Oman) | Rashdi, Mohammed (Petroleum Development Oman) | Nazaruk, Dariusz (Petroleum Development Oman)
Abstract 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.
Abstract Acid Fracturing has been one of the most effective stimulation technique applied in the carbonate formations to enhance oil and gas production. The traditional approach to stimulate the carbonate reservoir has been to pump crosslinked gel and acid blends such as plain 28% HCL, emulsified acid (EA) and in-situ gelled acid at fracture rates in order to maximize stimulated reservoir volume with desired conductivity. With the common challenges encountered in fracturing carbonate formations, including high leak-off and fast acid reaction rates, the conventional practice of acid fracturing involves complex pumping schemes of pad, acid and viscous diverter fluid cycles to achieve fracture length and conductivity targets. A new generation of Acid-Based Crosslinked (ABC) fluid system has been deployed to stimulate high temperature carbonate formations in three separate field trials aiming to provide rock-breaking viscosity, acid retardation and effective leak-off control. The ABC fluid system has been progressively introduced, initially starting as diverter / leak off control cycles of pad and acid stages. Later it was used as main acid-based fluid system for enhancing live acid penetration, diverting and reducing leakoff as well as keeping the rock open during hydraulic fracturing operation. Unlike in-situ crosslinked acid based system that uses acid reaction by products to start crosslinking process, the ABC fluid system uses a unique crosslinker/breaker combination independent of acid reaction. The system is prepared with 20% hydrochloric acid and an acrylamide polymer along with zirconium metal for delayed crosslinking in unspent acid. The ABC fluid system is aimed to reduced three fluid requirements to one by eliminating the need for an intricate pumping schedule that otherwise would include: a non-acid fracturing pad stage to breakdown the formation and generate the targeted fracture geometry; a retarded emulsified acid system to achieve deep penetrating, differently etched fractures, and a self-diverting agent to minimize fluid leak-off. This paper describes all efforts behind the introduction of this novel Acid-Based Crossliked fluid system in different field trials. Details of the fluid design optimization are included to illustrate how a single system can replace the need for multiple fluids. The ABC fluid was formulated to meet challenging bottom-hole formation conditions that resulted in encouraging post treatment well performance.
Abstract In the previous experimental and modeling works on the stimulation of carbonate reservoirs, the chemical composition of dolomites was assumed to be (1) as of ideal mineral, i.e., CaMg(CO3)2, and (2) constant within the reservoir. However, a discussion and list of references provided in this study show that: (1) most sedimentary dolomites contain Ca in excess of ideal composition and should be represented by formula Ca1+xMg1-x(CO3)2, (2) excess Ca dolomites dissolve up to 2.2 times faster compared to ideal ones, and (3) Ca uptake varies within the reservoir. This work aimed to determine the effect of vertical variation in the chemical composition of dolomites on the efficiency of stimulation operations. Two commercial software programs were used to model acid fracturing in dolomitic reservoirs. Both of them predict similar results; compared to the reservoir layers comprised of almost ideal mineral, layers with excess Ca dolomites have: (1) more than two times higher acid-etched fracture width, and (2) 40–100% higher fracture conductivity after closure. Excess Ca content in dolomite can be quantified by relatively simple X-ray diffraction analysis with an internal standard. Therefore, one should determine the variation of Ca content in dolomites across the target zone as this impacts the strategy of stimulation.