The application of acid fracturing techniques to deeply buried carbonate reservoirs is often an attractive option due to acid's ability to penetrate/improve natural fracture production where a gel frac fluid may damage the natural fractures. However, effectiveness of acid can be limited due to depth, temperature, and high in situ stress. The introduction of acid creates surface roughness or asperities that hold the fracture open under reservoir conditions, but all three factors above diminish the applicability of acid etched fractures. Under extreme stress these fractures close unless artificially propped open in some fashion. The advantage of combining the two approaches (acid+proppant) is not only an improvement in the natural fracture conductivity through the acid etching, but also yields a longer lasting conductivity in the main fracture from the emplacement of the proppant. The idea of adding proppant to an acid fracture stimulation job has a long history but has seldom been used due to a fear (not unfounded) of proppant flowback, and the lack of design tools to quantitatively identify proper candidates. Additionally, models based upon the classic Nierode-Kruk correlations were often over-optimistic in predicting fracture conductivity under high stress conditions, disguising the potential need for combination treatments. Recent developments in modeling, especially the upscaling of laboratory data to field-scale, make it possible to evaluate the combination of both techniques. The completion design and post-test analysis of two recent acid+proppant stimulation programs in Middle-East carbonate reservoirs is examined. Case 1 was a 10m interval at a depth of 3600m (11,800 ft). Closure stress was 700 bar (10,000 psi). Case 2 was a 35 m thick interval at a depth of 2200 m (7000 ft) with an average porosity of 20% and permeability of > 5 mD as determined from wireline logs. Reservoir temperature/pressure for this case were 120 C (260 F) and 250 bar (3600 psi), with an in-situ closure stress of 350 bar (5100 psi). The formation was characterized by the homogeneous distribution of porosity/permeability.

The Magallanes Basin of Southern Chile is the southern-most hydrocarbon-producing basin in the world. The main source of the gas production in this basin is from the Glauconite Formation. The Glauconite is a clay and feldspar rich formation with extremely low permeability requiring hydraulic fracturing to recover the hydrocarbons and enhance well performance. In this project, fracture simulations with a fully three-dimensional finite element model were integrated with statistical analysis and used in an optimization study of hydraulic fracturing in the Glauconite Formation. The mechanical earth model was used to estimate the in-situ stress contrast, Young's Modulus, and leak-off profile with depth. Tri-axial compression tests of core were used to validate static Young's Modulus estimates while mini-frac data and fracture stimulation data were history matched and used to validate and/or modify in-situ stress and leak-off profiles with depth. The history matched treatments were then used to populate the database with the resulting hydraulic and propped fracture dimensions. Ultimately, a database that includes in-situ stress, stress contrast, Young's Modulus, leak-off, propped and un-propped fracture dimensions (length and conductivity) was developed. Finally, both the database and multi-variate statistical analysis were used to show the role of mechanical earth modeling in enhancing and improving the understanding of fracture optimization in the Glauconite Formation. Results from hybrid fracture fluid treatments were compared to treated water fracture treatments to determine the optimum fracture stimulation design for this unconventional extremely tight gas resource. This work provides a benefit to the petroleum industry by: Using a geo-mechanical finite element model to improve the understanding of the propped fracture dimensions achieved by hybrid and treated water fracture treatments in an unconventional resource like the Glauconite Formation. Establish the key drivers for successful water-frac treatments.

In an unconventional reservoir exploration process, the horizontal stress profile across different rock types plays a critical role for drilling and frac design optimization. Present study provides insight about the challenge of estimating stress profile and breakdown pressure in tight sandstone gas reservoirs at 4900m-5500m TVD with varying petrophysical parameters across a complex geological setting. A geomechanical model is prepared prior to a hydraulic fracturing job based on open hole geophysical logs and history match borehole images features like breakouts and drilling induced fractures. Advanced sonic shear fast & slow radial profiles are inverted to directly estimate horizontal stress profile in applicable formations to constrain strain at different well locations. This helps to map changes in stress magnitude, contrast and direction in reservoir across different exploration areas. Algorithm has been successfully implemented earlier worldwide in deep water and has been tested successfully in tight shallow sandstone where dispersion data shows crossover of fast & slow shear near wellbore due to hoop stress. 3D anisotropic data from advanced sonic measurement has been utilized to predict true rock fabric based rock mechanical, elastic and stress profile in silty layers. It helps to understand containment of frac across different reservoirs and optimize stages. Rock types based on petrophysical results, image features and estimated breakdown pressure were used as reference for choosing frac stages. Post-frac closure and breakdown pressure values came close to estimated values using geomechanical results and provided confidence in strain values at different fields. Breakdown pressure seems to vary in range of 12500 psi to 19000 psi depending on stress and rock quality for same reservoir. Stress barrier at top of one reservoir vary at various locations as confirmed with tracer and pressure history match which was predicted using geomechanical model. This integrated petrophysical-geomechanics workflow has been utilized in two vertical wells for two reservoirs successfully to understand field level variation in closure and breakdown pressure and map degree of anisotropy with geological variation. Cost effective optimization of Frac design have been achieved through proper integrated approach saving rig time in decision making and avoiding extra stage as confirmed through Tracer logs.

The current practice of pumping large volumes of low salinity slick water in hydraulic fracture stimulation treatments in Canadian oil and gas shales and ultra-tight formations has proven extremely beneficial. These zones, however, are typically considered to have sub-irreducible water saturations. Nevertheless, water treatment volumes of 10,000 – 20,000 m3 per well are routinely performed. Conventional thinking would expect reduced hydrocarbon production due to formation damage or water block. Cleanup efficiencies of these massive water volumes during flowback is driven by the desire to minimize fluid invasion into the matrix. Water (load fluid) cleanup is essentially driven by viscous forces to counteract the capillary forces in the mix-wettability pore network. Operational and seasonal restrictions at times prevent wells being tied into pipelines immediately to continue the load fluid clean-up process. Once wells are placed back on production however, positive and dynamic fluid changes are observed. Conventional thinking suggests that once the invaded water zone saturation reduces to irreducible levels during flowback (cleanup operations), hydrocarbon can then freely flow into the wellbore. However, the flowback behavior in unconventional reservoirs is quite different than conventional reservoirs where soakback and slowback techniques are implemented. These wells can undergo weeks or even months of shut-in following the hydraulic fracturing treatment. It is believed that extended shut-in periods promote the counter-current imbibition phenomena, where the residual hydraulic fracturing fluid can imbibe deeper in the formation matrix driven by osmotic and capillary forces. This paper demonstrates the true benefit of multi-functionalized surfactant (MFS) with formations of mixed-wettability characteristics using both lab and field tests. Amott Cell results, a test for spontaneous imbibition using various stimulation fluid types, demonstrated MFS significantly outperformed common surfactant chemistry when tested on mixed wettability core samples.

The use of the Diagnostic Fracture Injection Test (DFIT) technique as a means of pre-frac investigation has become relatively routine in the oilfield, particularly to understand the reservoir properties and then subsequently optimize the hydraulic fracture design. A key component of an effective DFIT is the performance of an effective After Closure Analysis (ACA) to assess the transmissibility of the formation and thereby allow for effective design. BP Oman is developing the Barik formation, within the Khazzan field, which is a low-permeability conventional tight-gas reservoir within Block 61 of the Sultanate of Oman. The reservoir is comprised of a series of tightly interbedded sandstones and shales, with substantial shale breaks between the principal sand lobes. During the Appraisal and Development well sequence to date, BP Oman have performed DFIT operations in over 50 vertical wells, within the Barik Formation. Each one of these wells was then subject to placement of a large (one million lb) hydraulic fracture treatment. Each treatment was then followed by a standard clean-up programme and when possible a PBU, with subsequent placement on production into the main gathering system. This paper seeks to demonstrate that there is unambiguous evidence of a coherent correlation between the petro-physical Barik open-hole logs, the transmissibility value (as estimated from the ACA), the conventional Pressure Transient Analysis (PTA) as well as the long-term production behaviour. Additionally, the paper will investigate the key aspects of the actual DFIT execution, the data gathering and the analysis that can impact the quality of the correlation. The paper will go on to demonstrate the most efficient methods of achieving the most accurate assessment of the formation transmissibility; that is both indicative and subsequently helpful for the fracture design and post-fracture productivity prediction. This paper successfully describes a 50 well, and growing, DFIT analysis programme and the suitability of the use of the results from the subsequently performed ACAs for forward planning and hydraulic fracture design. Providing a suite of useful and helpful insights, suggestions and recommendations; into how DFIT, for ACA, should be executed in the field; the paper adds an extensive case history to the industry database for future consideration.

In unconventional reservoirs, the presence of natural fractures coupled with high pore pressures leads to the creation of complex fracture networks. During drawdown, the fracture network experiences large changes in the stresses which can affect the fracture conductivity, and hence the production rate. We present a workflow to find an optimum drawdown strategy in which the fractures can remain conductive while maintaining a high enough drawdown to maximize production. A fully coupled geomechanical reservoir simulator is developed to simulate production from complex fracture networks. Flow in the fracture and reservoir domains is solved in two separate conforming meshes which are coupled through matrix-fracture transfer indices. The complex fracture network is represented as an explicit discontinuity in the reservoir domain which is essential to capture the stress variations in the vicinity of the fractures due to reservoir depletion and fracture closure. The fracture closure process is modeled dynamically using the Barton-Bandis contact relationship, and the fracture conductivity is determined using the fracture width and proppant concentration. This model is used to study the impact of drawdown strategy on fracture conductivity and well productivity. It is observed that the estimated ultimate recovery (EUR) from complex fracture networks depends upon the connected fracture conductivity and the applied drawdown. A conservative drawdown strategy maintains the fracture conductivity for a longer period but results in a lower initial production rate. As the drawdown is increased, the unpropped fractures close and can cause a large portion of the fracture network (the part behind the closed segment) to get disconnected from the wellbore. This reduces the available fracture area for production. Although an aggressive drawdown strategy results in higher initial production rates, it can lead to faster fracture closure, in turn resulting in a lower EUR. Impact of drawdown strategy on productivity is analyzed at different fracture closure rates. We show that the optimum choke management strategy depends on the sensitivity of the fracture conductivity to stress. A coupled geomechanical reservoir model is presented that can simulate production with dynamic fracture closure in complex fracture networks to quantify this effect.

Optimizing horizontal well placement is often not limited to identifying the most favorable reservoir, but also identifying the ideal target window within that reservoir. In unconventional reservoirs, the ideal target window must have both appropriate reservoir quality and the mechanical rock properties conducive to effective hydraulic fracturing. This paper presents two case studies from the Permian Basin. The first study directly compares wireline logs and core data with drilling vibration analysis. Analyzing drill bit vibrations, one can process mechanical rock property data. This process is called drill bit geomechanics. These high-resolution drill-bit-derived data were first calibrated to wireline and core data, then applied to target future landing zones. The second case study compares drill bit geomechanics data across three neighboring 10,000-ft horizontal wells, all of which landed in the same target zone. Based on the drill bit geomechanics data, the three wells showed notable differences in mechanical rock quality. The operator found the three wells’ production responses also differed. High frequency measurements of drilling-induced vibrations were recorded through several producing Permian reservoirs. In the pilot well, the recording tool was run behind a coring assembly to obtain mechanical data at in-situ pressure and temperature. Elastic stress-strain relationships were used to solve for the stiffness coefficients and determine relative values of mechanical properties (i.e., Young's Modulus (YM) and Poisson's Ratio (PR)). The resulting mechanical data were compared directly to core analysis, wireline dipole sonic logs, and wireline image logs. In general, the mechanical rock properties derived from drilling vibrations compared well with those from the sonic log and core analysis. One can attribute differences between the datasets to fluid effects and differences in resolution. The drill-bit-derived mechanical properties showed fine-scale changes and thinly-bedded intervals that were not identified by the sonic log. Using sonic measurements to determine in-situ mechanical properties can have non-uniqueness. Analyzing cores also includes challenges of translating exhumed core properties to those of in-situ conditions. Combining the in-situ measurement of mechanical properties from drilling vibrations with the traditional sonic log and core analysis minimized uncertainties. Increased understanding of mechanical properties in the pilot well informed the landing zone target intervals for the horizontal well development plan. Understanding mechanical properties is also critical to effective hydraulic fracture stimulation design and execution. Even within a landing zone, mechanical properties can vary laterally. Measuring and understanding these variations in mechanical properties can improve completions and lead to increased well productivity. Gathering drill bit geomechanics data provides a lower cost and lower risk method to acquire mechanical rock properties in long, horizontal wellbores. These near-wellbore variations in mechanical rock properties are ideal for use in identifying target landing zones for horizontal wells. One can use the data to create high-resolution, laterally variable fracture simulation and reservoir models. By integrating these data sets with mechanical rock properties recorded while drilling, operators can have significantly higher confidence in choosing a target landing zone and improving completions.

From using history matching to recording microseismic; exploration, completion, and production groups in the oil and gas industry don't know exactly where stimulation treatments are placed and how efficient that placement has been. Exploration geologists and geophysicists want to know placement effectiveness to relate current geologic parameters with future potential formations. Completion engineers want to use tubular and downhole hardware systems to be as cost-effective as possible and to minimize total stimulation treatment cost. Production engineers are seeking to maximize production for as long a time frame as possible. Fracturing placement and verification cuts across all segments of an asset. With recent technology and methodology advancements, the industry can inject particulate oilsoluble tracers (OST) with the proppant and measure those tracers effectively from fracture tip to production tank. While still not accurately describing the exact fracture geometry or parameters such as fracture conductivity (fcd), the industry can now qualitatively measure production from each stage. With each stage uniquely identified by post-fracture production, fracture size and capital expenditure associated with the placement of the fracturing treatment can be optimized. Broadview Energy recently pumped a fracturing treatment into the 637 m (2089 ft) total vertical depth (TVD) Sparky clastic zone through a 114 mm (4.5") liner string in a horizontal wellbore using mechanically operated sleeves. Broadview Energy sequentially alternated the size of the fracturing treatments along the length of the well between 7.5 t (16, 534 lb) and 5 t (11,023 lb) of 16-30 fracturing sand as the proppant. Alternating the fracture size served to isolate geologic and fluid heterogeneities. Measuring the OST concentration from each fracture treatment showed results that were not directly proportional with the size of the treatment; namely, a 50% larger stage treatment yielded a 33% improvement in OST return. Using tracer technology to show observable variations of completion methods, Broadview Energy hypothesizes that, with further testing, it would be possible to recognize the threshold in fracture size and prevent diminishing returns in future fracture treatments with similar geologic conditions.

During hydraulic fracturing, the interaction of hydraulic fractures with natural fractures can result in the formation of complex fracture networks. In the past these interactions have been captured in hydraulic fracturing models using crossing criteria developed based on two-dimensional geometries. In this work, we investigate the interaction of hydraulic fractures and natural fractures in three-dimensions and demonstrate that there can be significant differences in the observed interactions. A hydraulic fracturing simulator is presented that solves the coupled fluid flow and geomechanics problem for three-dimensional fractures. The simulator captures the physics of fracture growth and the intersection of hydraulic fracture with pre-existing discrete fracture network. The model employs a robust algorithm to account for the stress relaxation due to the slippage of natural fractures. The displacement of failed natural fracture elements is calculated rigorously. The model allows the partial failure of three-dimensional natural fractures and accurately calculates the stresses acting on the plane of the natural fracture. It is shown that a natural fracture inclined at an angle to an approaching hydraulic fracture experiences compression in one region (due to the stress shadow of the growing hydraulic fracture) and tension in other regions (in front of the approaching hydraulic fracture tip). The generated stresses can fail the natural fracture partially. The failure of the natural fracture relaxes the stresses around it, which can modify the direction of propagation of the approaching hydraulic fracture. In addition, if the elliptical front of the hydraulic fracture crosses an intact planar natural fracture, the three-dimensional geometry results in a line of intersection (between natural fracture and hydraulic fracture). This can lead to failure of the natural fracture even after the elliptical front has partially crossed the natural fracture. Such an interaction can allow the hydraulic fracture to both cross the natural fracture and activate (or dilate) it. These effects cannot be captured by two-dimensional simulations. This work improves our understanding of the interaction between hydraulic fractures and natural fractures. The novel results provide new insights into the mechanisms responsible for the complexity that is often observed in hydraulic fractures.

Changning National Shale Gas Demonstration Area was established in 2012. Field Development of its Ning201 shale gas fields was geared up in 2014. By 2015, Changning area accomplished the construction of 15×10 8 m 3 /a production capacity. During early appraisal phase before 2014, average testing results of wells were 10~15×10 4 m 3 /d. In the end of 2016 and early 2017, average testing results of large numbers of wells across multiple pads achieved over 25×10 4 m 3 /d. Overall testing results of some pads have exceeded 180×10 4 m 3 /d per pad, and some of them may exceed 180×10 4 m 3 /d per pad in soon future. Through implementing geo-engineering integration, efficiency and effectiveness of field development have been steadily enhanced. This paper reviews our practices to establish and rapidly evolve the learning curve in this national demonstration area through geoengineering integration. Benefiting from geo-engineering integrated study, development options were systematically, proactively and effectively supported throughout the process of field development. Per the evolving understanding of reservoir and engineering challenges, adaptive technology and engineering solutions were exploited and optimized. A new geo-engineering model has been proposed which covers engineering applications of drilling, completion, production and development. Based on our gathered knowledge and experience, key contributing factors for marine shale gas development in Sichuan basin were thoroughly studied and summarized. They may include controlling factors of productivity, optimum production scheme, optimized well spacing, and so on. This paper also points out key areas for further improvement and enhancement in future.

Completion and production stimulation engineers use isotropic or transversely isotropicwith a vertical axis of symmetry (TIV) mechanical earth models (MEM) as an input to predict hydraulic fracture (HF) height growth. Occasionally the MEM results in models that predict fracture heights at odds with the observed fracture height in the field (e.g., fracture hits, microseismic monitoring). A potential solution to this discrepancyis to add rock fabric into the HF modeling process to better match the containment boundaries observed in the field. Laboratory large-block experiments have shown the importance of rock fabric for HF height growth and containment. Rock fabric in organic-rich mudstones (e.g., Barnett) andhybrid sequences (e.g., Wolfcamp, Eagle Ford), results from the depositional and diagenetic history of the basin andcomprises different elements relevant to HF modeling. Key rock fabric elements include: a) thin, hard layers (named stringers); b) weak beds (e.g., ash beds); and c) weak interfaces (e.g., mineralized fractures, lithology contacts). The firstchallenge in usingrock fabric elements is identifying them with wireline logs (e.g., sonic logs). Because these features are thin, often only a few inches thick or less, they are less than the vertical resolution of most sonic logs. For thatreason, they are generally not considered in the creation of a MEM, which is the key input for modeling HF height growth. A novel rock fabric analysis workflow specifically targeted to HF height growth has been developed. It is based on high-resolution borehole images and the interpretation of the interaction of tensile drilling induced fractures with rock fabric. Qualitative flags (thickness and density of occurrence) are generated for all rock fabric elements found relevant to HF height containment, for subsequent integration into HF modeling. This offers a data-driven workflow to solve discrepancies between the hydraulic fracture heights predicted by models and those observed in the field. For weak interfaces, these flags are integrated into hydraulic fracture models as boundaries where the rock will undergo shear displacement and the fluid flow will experience complexity in its vertical path that will lead to effective containment. It is important to note that a single boundary might not stop fracture propagation, but rather a succession of boundaries is typically required to sufficiently contain a hydraulic fracture.

The Andrew asset is a strategic hub for BP in the Central North Sea and has been producing from the Palaeocene oil reservoir for the past twenty-two years through a small fixed platform. In addition to the conventional Palaeocene oil reserves, there is an underlying Lower Cretaceous gas-condensate reservoir. The A11z well was drilled as an appraisal well within this low permeability formation and the original completion in 1998 was designed with the intent of performing a future hydraulic fracture. Extended well tests however, identified that gas production facilities were required for production and these were not provided until platform redevelopment in 2015. The stimulation operation has been delayed since due to the highly complex interfaces on an ageing asset and prioritisation of plant reliability work scopes and other simpler intervention work scopes. Due to the increasing strategic importance of a new black start gas well for the asset hub, the alignment of priorities between the different functions was addressed and the hydraulic fracture operations were executed in June 2018. A multi-disciplinary project team has been established with a remit to manage and simplify the work scopes, enabling an efficient stimulation operation and a safe flowback with minimal impact to the platform reliability. The optimal design for a reliable proppant hydraulic fracture treatment has been crucial to deliver this Regional objective. The stimulation execution was one of the largest single stage proppant placements for the basin in recent history. The implementation of single mesh proppant for the entire job is a unique deployment for the Region and a novel movement in the global stimulation industry in general, as was the first application of fibres in the North Sea. In addition to the unconventional job design, the Andrew A11z stimulation has become the first proppant fracturing treatment to be executed by BP UK North Sea in twenty-two years. The successful execution and results of this complex project demonstrates how innovative stimulation design, when combined with effective multi-disciplinary team management and guided by aligned priorities adds significant long-term value but can also extend the life of mature offshore assets and instil confidence to pursue many more similar opportunities in such environments that are all too often discarded due to perceived complexity.

Closed-fracture acidizing (CFA) technique has been proved to be a successful practice in stimulating tight carbonate formations. Acid is injected at rates lower than fracturing pressure to enhance the fracture conductivity and productivity. CFA operations are often associated with acid wormholing, promoted by acid leak-off in the formation. The objective of this study is to develop a model that represents these wormholes demonstrating their performance in enhancing the acid fracturing treatment in tight naturally fractured dolomite reservoirs under field conditions and investigate the effect of different parameters on acid wormholing during CFA. The wormholes propagation is modeled by the two-scale continuum model by developing a 3D computational fluid dynamics (CFD) model including the fracture geometry, conductivity of the fracture and the reaction kinetics between the acid system and the formation. The formation that is utilized in this study is tight naturally fractured dolomite formation exhibits low transmissibility and a considerable degree of heterogeneity. Well geometry was investigated to analyze the effect of injection area in the closed fracture on acid wormholing. Sensitivity analysis was conducted to cover the effect of several factors including acid concentration, injection rate, formation permeability and fracture conductivity to depict the actual flow in the formation. The presence of natural fractures was studied with the emphasis on their orientation and direction with respect to the hydraulic fracture whether it is parallel or perpendicular. Model upscaling was investigated to come up with a qualitative relationship between the acid volumes used in CFA model and the acid volumes used in actual field scale. Acid injection rates in the closed-fracture in CFA operations follow a similar trend as the acid performance curve in matrix acidizing in term of dissolution patterns where a face dissolution pattern at the injection inlet of fracture occurs at low and high injection rates. Higher acid concentration accelerates the reaction between the acid and rock matrix and yields faster results than the lower concentrations. Vertical wells exhibit larger injection area in contact with the closed-fracture than the horizontal wells, which promote larger propagation of these wormholes with less total inject volumes of acid during CFA. Formation permeability coupled with acid fracture conductivity have significant role in the acid volumes used in CFA that are required to deliver the acid certain distance in the formation, and it affect the wormholing density significantly. The presence of natural fractures in the parallel or transversal direction with respect to hydraulic fracture play a key role in generating flow networks between hydraulic fracture and natural fractures that are induced by the acid leakoff in the formation regardless of the intersected natural fractures with hydraulic fracture. Model upscaling demonstrates the relationship that clarifies the total acid volumes injected in actual field applications that have to be used in the design of optimum acid fracture stages in multistage acid fracturing and to estimate the optimum spacing between the stages which will maximize the performance of this completion.

Giant Ordos basin, located in the northern China, consists of Palaeozoic lacustrine stacked sandstone and shale deposits characterized by low-pressure, low-porosity, low permeability matrix rock and a poorly developed natural fractures (NFs) system. Recognizing the successful exploration of shale gas reservoirs in United States, Changqing oilfield primarily uses three fracturing technologies, hydraulic sandblasting technology, open-hole packer technology and drillable bridge plugging technology, to create multiple straight hydraulic fractures (HFs) in tight sandstone zones with large differential horizontal stress. For this study we consider multiple perforation clusters per stage using the drillable bridge plugging technology, which offers benefits of large injection rate and high treatment efficiency. This paper describes a hydraulic fracture propagation model (HFPM) that couples fracture deformation and fluid flow to simulate the growth of multiple HFs in the horizontal wellbore. We then integrated an embedded discrete fracture model (EDFM) and commercial reservoir simulator to analyze production prediction based on the provided data from Changqing oilfield. We calibrated the fracture propagation model with the reservoir performance data and demonstrated how to optimize the fracture treatment. The low formation pressure gradient in the Changqing oilfield impairs the production performance. To reduce the rapid decline rate in reservoir pressure, the fracturing fluid is not only used for creating fractures, but also enhancing the pore pressure by leaking off into the formation. Adjusting the pumping rate and fluid volume enables our model to increase the formation pressure gradient. Moreover, the tight sandstone deposits in the Changqing oilfield have a relatively high brittleness index (BI) and large differential horizontal stress. This is the reason why reservoir with sparse NFs in the Ordos basin has less opportunity of generating complex fracture networks. Large-scale physical simulation experiments were also conducted to validate the possibility of fracture networks generation. Our model accouts for the stress heterogeneity and offers the capability to address HF propagation in the presence of sparsely distributed NFs and adjusts the dimensions and spacing of the NFs to achieve a history match with production data. This paper emphasizes the extensive application of a fracture propagation model for lacustrine tight sandstone deposits. Considering features of Ordos basin, such as low-pressure gradient and relatively high BI, our model can provide a guideline for HF treatment design and optimization of well performance.

Multi-stage acid fracturing of horizontal wells is a necessary and effective technology in developing tight carbonates. In open-hole horizontal wells in high-temperature, naturally fractured deep formations, segmentation with tools is of high risk and costly, even ineffective sometimes, so segmentation with diversion agents is alternative to tools and was pilot tested in some fields. The stimulation results were satisfactory, and pressure response feature was in accord with expectation. However, this technique has not been studied experimentally or numerically extensively yet. In this study, we investigated tool-free multi-stage fracturing experimentally in open-hole horizontal wells with diversion agents. Firstly, we designed a multi-stage tri-axial fracturing system and experimental procedures to satisfy the requirements of diverted fracturing in horizontal wells. Next we conducted a series of experiments to investigate feasibility of multi-stage fracturing with diversion agents using natural carbonate outcrop cubic blocks with the size of 300*300*300mm. CT scanning was used to obtained detailed fracture geometry after experiment. Finally we analyzed the effect of diversion agent type, concentration, and injection procedure on diversion. The experimental results show that multi-stage fractures perpendicular to the open-hole horizontal wells was created, which verifies the validity of the tool-free multi-stage fracturing of open-hole horizontal wells with diversion agents. Proper agents or combinations can effectively plug the fracture generated previously and generate pressure high enough to initiate another fracture. The breaking pressure or propagation pressure of second fracture was monitored higher than the one of the first fracture. Under experiment conditions, 1-3mm fiber or combination of fiber and particle (0.8-1.2mm) can effectively plug fractures and realize segmentation. Concentration of diversion agents tested ranges 0.4-1.6wt%. Injection procedure for two-stage fracturing was fracturing fluid + diversion fluid + fracturing fluid. The amount of diverter and open-hole length are the vital factor for the success of experiments. This study newly designed a multi-stage tri-axial fracturing system and experimental procedures for the diverted fracturing. The finding verified the validity of the tool-free multi-stage fracturing of open-hole horizontal wells with diversion agents and provides fundamental for field treatment design.

Particulate diversions are widely used for stimulation treatments. Usual field practice is to increase the volume of solid particles to create a considerable pressure response. However, an excessive dose of particles challenges particle removal and results in unexpectedly longer clean-up time. Self-degradable particulate diverter systems can overcome this shortcoming. The current study investigates the mechanisms of self-degradable particle transport and progressive clogging involved in fluid diversion. Engineering solutions and case studies for applying this new diversion technology in fracturing unconventional formations and acidizing carbonate reservoirs are discussed separately. An integrated workflow and numerical models have been established and verified with experimental data and field experience. In the hydraulic fracture stimulation analysis, a wellbore-scale computational fluid dynamics and discrete element method (CFD-DEM) is employed to understand the physics of particle slurry transport and particle jamming at an opening. A three-dimensional reservoir-scale simulator is used and coupled with particulate diversion mechanisms for fracturing. To simulate the carbonate-acidizing procedure, an in-house numerical engine was developed and used to design the diversion of acidic fluid. The stimulated reservoir extent and associated production are predicted to compare the fluid diversion efficiency between various designs and to show the robustness and effectiveness of engineered particle designs. Two field data sets are utilized to demonstrate the applications of new particulate diverters in hydraulic fracturing and matrix acidizing respectively. Analysis suggests that the success of the new diverter system application is governed by the particle characteristics (size, shape, ratio and concentration) and diverter slurry displacement (rate, viscosity and volume of displacing fluid). The models and workflows are capable of designing fit-for-purpose diverters and their application in different stimulations, including both hydraulic fracturing and matrix acidizing. As demonstrated in our studies, non-engineered designs could result in low fluid-diversion efficiency or even failure of reservoir stimulations. Engineered self-degradable particulate diverters can plug the openings (including perforations and induced wormholes) and withstand differential pressure to divert stimulation fluid (either fracturing slurry or acidic fluid) into under-stimulated regions for effective fracturing and acidizing. According to our case studies, particulate diverters can be designed to enhance fluid diversion efficiency and optimize the use of particles. The case studies demonstrate the practical applicability and advantages of using self-degradable particulate diverters in both hydraulic fracturing and matrix acidizing operations. The integrated workflow and analysis proved useful to guide the field executions for successful fluid diversions.

The Devonian Duvernay Formation in Alberta, characterized as a carbonate-siliceous source rock, is ramping up to be one of the largest and most prolific shale oil plays in Canada. In the southern part of the Duvernay Shale Basin (i.e. East Shale Basin), tight limestone beds are interbedded with laminated organic-rich calcareous shales, which show an organic maturity ranging mostly from early oil- to condensate-window. This new light oil shale play is still in the initial stages of development and the nature of these deposits requires hydraulic fracturing to increase stimulated rock volume. General completion programs involve ≥50 clustered plug ‘n’ perf stages with slickwater treatments in excess of 40,000 m 3 with ~4000 tonnes of proppant per well. The large water volume treatments will inevitably interact directly with the rock surface in the stimulated area and cause both oil-water and rock-water interactions. Post-hydraulic fracturing water retention is especially pronounced in light oil shale plays. The oil-wet nature of the Duvernay, along with calcareous and siliceous shale lithologies, adds to the complexity of water retention and perceived water-blockage. In addition, because of operational delays such as road bans and pipeline constraints, some wells may be shut-in after the fracturing treatment for weeks and even months, which will affect rock-oil-water behavior (i.e. production). The extent of water displacing into the matrix of the rocks of the Duvernay Formation in the East Shale Basin, as measured by load fluid recovery, varies significantly and appears to heavily rely on the choice of surfactant. Although the use of surfactants is generally accepted for this play, detailed understanding of the rock-fluid interaction mechanisms is still incomplete. This paper investigated the response of Duvernay Shale rocks from the East Shale Basin to various types of surfactants and analyzed production and fluid flowback data. Amott Cell analyses, which test for spontaneous oil displacement using various stimulation fluid types, demonstrated that in the East Shale Basin, nano-sized surfactants including multi-functional surfactants (MFS) and microemulsions significantly outperformed common surfactant chemistry when tested with mixed wettability shale core samples. The results provide an estimate as to extent of water migration into the matrix of the Duvernay as a result of the choice of surfactant. Our analysis is made possible from publicly available cores, laboratory analysis and high quality well production data from the Alberta Energy Regulator.

Seven years ago, some operators in the United States began geo-engineering completions to more efficiently stimulate unconventional horizontal wells. Typically, engineers and geoscientists rely on expensive open-hole logs or the over-simplified use of gamma ray to infer mechanical rock properties along the lateral. Engineers then select treatment stage intervals and place perforation clusters in similarly-stressed, "like rock" to minimize the geomechanical variability. Instead of traditional open-hole logging, this paper discusses geo-engineering applications of drill bit geomechanics. Drill bit geomechanics is an innovative method for formation evaluation and reservoir characterization. It uses direct, continuous, high-resolution measurements of drilling vibrations recorded downhole. Using earthquake seismology models, one can infer rock properties from the measured drilling vibrations. These rock properties include Poisson's Ratio, Young's Modulus of Elasticity, and the presence of fractures perpendicular to the horizontal well. In this study, the Operator collected drill bit geomechanics data while drilling a new well ~8-34 ft below three existing horizontal wellbores, with over seven years of continuous production. The study well was a 9,500-ft lateral in the Bakken Formation in North Dakota. Using drill-bit-geomechanics-derived rock properties, the operator could confidently geo-engineer a completion, accounting for reservoir depletion from the older wells. The drill bit geomechanics data showed dramatic changes in mechanical properties and fracturing where the study well intersected the older wells’ stimulated reservoir volumes (SRVs). The operator had a general idea of the wells’ SRVs from microseismic data acquired during two wells’ stimulations. Using the drill bit geomechanics data from the study well, the operator could more effectively constrain the drainage ellipses from the sparse microseismic data. The operator geo-engineered a 27-stage completion by combining "like rock" of the same reservoir pressure. Measured Instantaneous Shut-In Pressures (ISIPs) during the completion showed significantly lower ISIPs for the partially-depleted stages closest to the older wells. Thus, combining similarly-pressured stages was critical to the completion's success. Well performance has proven to be excellent for the area, even when compared to wells without depletion from older producing wellbores. As shown in this case study, drill bit geomechanics is an economic, useful tool to identify depletion and accurately measure rock properties and fractures at a very high resolution.

In naturally fractured carbonates, the efficiency of acid fracturing stimulation can be hindered due to the decreased effective length and conductivity of created fractures, and acid loss into natural fractures is one of the main reasons for the reduced efficiency. At the same time, acid that leaks into natural fractures creates additional conductivity that may enhance production from the stimulated well. A model was developed to predict the acid fracturing performance in naturally fractured carbonate reservoir by taking into account the etching of both hydraulically induced and naturally occurring fractures to estimate fracture conductivity and well productivity. The model uses a domain that contains a well and a rectangular reservoir. The well is intersected by a bi-wing vertical hydraulic fracture which is intersected by transverse natural fractures. The model simulates acid injection into the fracture system, acid-rock reaction, and width increase for both hydraulic and natural fractures. At the end of the acid injection, the conductivity of the fracture system is estimated, and the well stimulation efficiency is evaluated by calculating productivity increase and skin factor. This is done by simulating the production flow into the hydraulic and natural fractures using a coupled reservoir model without the need of an external reservoir simulator. In contrast to previously published acid fracturing models which calculate leakoff using the Carter's model, in this study, we developed a model that calculates the leakoff during acid injection by simulating the flow through porous media using a reservoir model, which includes both hydraulic and natural fractures. In contrast to the Carter's leakoff model which assumes that fractures are spaced far enough so that no interaction among the fractures occurs, the new approach allows the natural fractures to interact with each other as acid leaks off and pressure changes in the reservoir surrounding the fractures. The new approach does not impose limitations on fracture spacing, and leakoff rate of individual natural fractures is a function of fracture spacing and location. The other feature of the new model is that the leakoff flow rate does not necessarily decrease with time, unlike what Carter's leakoff model predicts. It was observed that leakoff rate from natural fractures may increase initially as the natural fractures are stimulated. The effects of natural fracture geometry and spacing, reservoir permeability, and treatment conditions on acid leakoff, fracture conductivity and well productivity are analyzed. The role of natural fractures on stimulation efficiency is evaluated by comparing the results with the cases where no natural fractures are present in the reservoir. The model enables a better prediction of acid fracturing performance in naturally fractured carbonate reservoirs, and also simulates more realistic leakoff behavior compared to the conventional leakoff model, which improves the accuracy of the results.

In this work, we assess the historical well performance for a mature gas condensate field in Oman (the field name is designated as "BHA," where "BHA" is a pseudonym). The reservoirs of the BHA field are complex and have low permeabilities which results in substantial uncertainty in reserves estimation, which in turn has resulted in regular modifications of the booked volumes. To confine these booked volumes, we employed two techniques: "time-rate" analysis (or Decline Curve Analysis (DCA)) and "time-rate-pressure" analysis (or Rate Transient Analysis (RTA)). To perform the decline curve analysis work we used Microsoft Excel to match data using both the Modified Hyperbolic (MH) and Power-Law Exponential (PLE) DCA relations. We also used the Kappa Engineering product "Topaze" to conduct the Rate Transient Analysis (or RTA) by first estimating reservoir parameters and then performing a simulation history match of both the rate and pressure data. The DCA and RTA models were both used to construct a 30-year forecast and 30-year EUR values were obtained using these forecasts. Finally, we created parametric correlations using estimated reservoir properties from RTA and the matched parameters obtained using the MH and PLE relations for DCA. The core purpose of this work was to provide assurance in the booked reserves volumes for these low permeability reservoirs and to obtain correlations of reserves and reservoir property estimates for fields like the BHA field.