The objective of this paper is to review the hydrofracturing experience in one of the Omani oil fields and to provide better understanding of geological and operational controls on the productivity of the fractured wells. The methodology adopted in the study relied on the geomechanical evaluation for understanding the hydrofracture geometry. In particular a geomechanical model was built and calibrated by history matching the simulated and field data. Further, the implications of the created hydrofracture geometry in productivity have been studied based on the conceptual understanding and actual production histories. Last but not least, the influence of operational parameters on the hydrofracture success has also been studied. The geomechanical evaluation concluded that it is likely that the hydraulic fracture’s growth is unconfined and downwards. Because of the combination of the unconstrained growth with relatively high reservoir permeability, the created fractures potentially are of limited length and of relatively good conductivity. According to a semi-analytical bi-linear production model, these parameters are nearly optimal for the particular reservoir. Preference for highly conductive and short fracture is due to reazonably high fluid mobility in the reservoir, high viscosity of hydrocarbons, and a relatively close well spacing. Horizontal well technology is an alternative to the hydraulic fracturing in the considered settings. Meanwhile the preference may be given to hydraulic fracturing if the commingling of the targeted unit with the overlying or underlying reservoirs is sought after. On the other hand, in the areas of structural deep, the unconfined downward growth poses a risk of connecting to the water zone. Production histories of the wells indicate that water inflow has a very pronounced negative effect on hydrocarbon production and thus must be avoided. The calibrated geomechanical model helps in choosing operational parameters that allow for proper hydrofracture design in the areas of structural deep. Nevertheless, horizontal wells will be beneficial in the areas where fracture connectivity to the water zone is likely. Finally, a review of the fracturing operations has been carried out to understand the potential for improving the success rate. Because of the overall limited number of hydrofracturing jobs in the field, the results are far from being definitive. Meanwhile it is possible to hypothesize on the range of optimal operational parameters. In particular, this study recommends using limited volumes of fracturing fluids and coarser proppant mesh. The choice is based on the necessity to avoid communication with the water zone and the requirement of a highly conductive fracture for the efficient drainage. The recommendation is supported by limited trials. A viable alternative is combining deviated drilling technology with hydraulic fracturing. In such combination longitudinal small volume fractures should be targeted. The benefits of production enhancement and potentially achieving better capital efficiency are then achieved through commingling production from several units and increasing wellbore connectivity with the reservoirs. Meanwhile, it is important to keep in mind that the economic benefits can be realized when applying each of the considered development options, i.e., i) vertical, or ii) deviated commingled fractured wells, or dedicated horizontal non-fractured wells. In the considered field the particular choice is driven by the current economic environment, thorough risk assessment, and operational efficiency.

The performance of acid fractured wells depends on the conductivity distribution along the acid penetration length, which is a function of reservoir properties, treatment design and execution. The previously published models for fractured well performance assume constant fracture conductivity, which cannot be achieved in acid fracturing operations. This work proposes a design optimization method where acid fracture and reservoir models are integrated. Fracture conductivity distribution along the fracture surface is considered in the optimization process. In the new integrated model, the acid transport and reaction is joined to the fracture propagation and heat transfer models. The dissolution patterns along fracture surfaces are generated, and that is converted to a conductivity distribution. To predict the fractured well productivity, the reservoir model is built using the input reservoir properties as well as the calculated acid fracture geometry and conductivity distribution. The acid fracturing parameters that lead to the optimum fracture productivity are determined with this integrated model. This method shows that there is an optimum productivity that can be obtained for a given acid treatment volume and reservoir properties. Design parameters such as flow rate, viscosity, acid concentration, acid treatment volume, pad, and overflush volumes, can be selected to achieve the optimum well performance. Reservoir permeability has an important impact on how acid fracture jobs should be designed. At low reservoir permeability, a more evenly distributed conductivity and long acid penetration length is preferred. This can be accomplished by injecting a retarded acid system at moderate to high flow rate. However, excessive fracture height growth should be prevented by carefully designing the injection rate and viscosity. For high permeability reservoirs, higher conductivity along a shorter acid penetration length is targeted. This can be obtained by selecting a more reactive acid system such as straight acid and injecting at moderate rates, or lowering injection rate of retarded acids. Minimum amount of pad should be used in this case. Still, the flow rate should be high enough to keep the fracture open during acid injection. This paper also shows how acid concentration and fluid stages can be designed to optimize productivity, and presents a procedure for selecting the acid treatment volume. A theoretical model which integrates acid fracturing and reservoir flow is used to implement the guidelines on optimizing acid fracture design parameters. This paper provides a scientific approach to determine acid treatment volume that yields the optimal outcomes of acid fracturing.

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.

Advances in fracture mapping and full 3D modeling have yielded new insights into hydraulic fracture geometry, but it is still impossible to predict height growth. Fracture mapping data collected from a large number of treatments in different basins yield a rule-of-thumb for expected fracture height over fracture length (aspect ratio), but in specific cases fracture design optimization requires a more accurate forecast for height growth. Calibrated models with full 3D fracture geometry will give the best results, but in many projects the available data to calibrate such a model is severely limited. Knowing this, the question this paper attempts to answer is: "Will using a full 3D model give more reliable predictions of fracture geometry (maybe height growth) compared with pseudo-3D models?". Using data from an instrumented field test and routine fracture treatments, the results of the different fracture models are tested. Even when detailed knowledge of stress and geomechanical properties are available, it is impossible to match observed fracture geometry using only conventional hydraulic fracture physics. So, even a full 3D model does not provide a true prediction of fracture geometry. Both pseudo3D and full 3D fracture models can match observed fracture geometry, but only by introducing additional parameters beyond conventional fracture propagation physics, such as formation lamination or fracture tip pore pressure. A full 3D model with default input parameters and conventional fracture physics yields a prediction of strong containment, even for modest stress difference between pay and overburden. This agrees in general with average observed geometry, but in specific cases, fracture height growth still occurs, showing that in these cases the model was inadequate and needs to be calibrated. Pseudo-3D models tend to overestimate height growth for default inputs, but that can also be modified to match the stronger containment often seen in practice. Therefore, no benefit is obtained from fully gridded simulation models in routine cases where critical inputs and calibration data are unavailable.

Since the first frac in 1954, around 250 of the 3000 exploration and production wells in the Netherlands have been hydraulically fractured. This study focusses on about 50 of the more recent fracs, of which sufficient production data, reservoir information and hydraulic fracture properties could be obtained for economic and data analysis. For each well, the production history has been analyzed with a commercial rate transient analysis software package. About half of the wells have a pre-frac production history while the other half have been hydraulically fractured immediately after drilling. For wells with pre- and post-frac production data two history matched analytical models were made. Those models were subsequently used to create two production forecasts, to determine the incremental production profile and to calculate the economic value added by each frac. For wells without pre-frac production data the history matched post-frac model was used two create two production forecasts, one with and one without a hydraulic fracture in place. The calculated economic values have been combined with reservoir properties (permeability, GIIP, stratigraphy, etc.) and frac data (proppant type, amount of fluid used, amount of proppant pumped, etc.), to form a dataset which was analyzed using a commercial data analysis tool to investigate perceived correlations. The results show that practically all analyzed fracs resulted in a production improvement, and most of the fracs resulted in positive economic value added. However, some resulted in an economic grey area (below EUR 5 million incremental discounted cash flow), and one frac even resulted in a negative value. Many reasons can be given for the distinction between economic and uneconomic projects. This paper shows that although multiple attributes influence the calculated economic value, some generic observations can be made. There is apparently no correlation between PI improvement, skin or kh and economic value. Remaining GIP is definitely important for economic value, but no generic correlation for reservoir pressure can be made. It was shown that wells often see more connected GIIP after fraccing. The results show that fracs in reservoirs with 80% depletion can still result in very economically beneficial projects, especially if the fracs increase the connected GIIP. Frac properties might very well be important for the determination of the economic value of fractures. However, no clear correlation between economic value and frac half length or proppant size could be found. On the other hand, the results show that larger amounts of (any) proppant pumped seem to lead to higher economic value. Last but not least, a relation between PI improvement and pre-frac skin was found. The study presented is the first portfolio analysis of fracced conventional gas wells in The Netherlands. Input and methods have been checked and results have been shared with several experts outside our organization.

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.

Hydraulic fracturing formations at temperatures >375°F is challenging because of the unavailability of suitable fluids with sufficient thermal stability. Applying low thermal-stability fluid for fracturing these formations causes rapid viscosity degradation, leading to high fluid loss and narrow fractures. This paper discusses strategies adopted in successful offshore high-pressure/high-temperature (HP/HT) formation multistage fracturing using lower gel-loading fluid. Commercially available gelled fracturing fluids are made using polysaccharides or their derivatives. Glycosidic linkages in polysaccharides begin breaking rapidly at temperatures >375°F, making polysaccharide fluids unsuitable for HP/HT hydraulic fracturing when significant fracture conductivity must be achieved. Strategies were planned to cool down the reservoir and bring the temperature into the polysaccharide fluid thermal-stability range. The reservoir's temperature is approximately 400°F and has a high clay content. Performing fluid/clay mineralogy interaction tests optimized the type and concentration of the clay control additive; performing stability tests on an HP/HT viscometer optimized the crosslinked fluid formulation with low polysaccharide gelling agent concentration. Considering well completion and reservoir complexity, a limited entry technique was used to achieve maximum zonal coverage. The polymeric clay control additive performed better than conventional salt in clay inhibition; it did not have a negative effect on fluid thermal stability. Metal-crosslinked fracturing fluid containing 45-lbm/1,000-gal gelling agent was stable for approximately 1.5 hours at 350°F; results were comparable with gel having 50-lbm/1,000-gal gelling agent. The strong metal-crosslink bond provided higher thermal stability to the gel. Based on petrophysical log analysis, six zones were identified for hydraulic fracturing treatment; however, during execution two zones were combined, so five treatments were successfully executed on a well with a bottomhole static temperature of 400°F in the Krishna Godavari Basin (eastern coast of India). A total of 1,000,000 lbm of high-strength proppant was placed into the formation using approximately 17,000 bbl of crosslinked gel. The zone was perforated in individual clusters; a limited entry technique was used to help treat the zone. The limited number of perforations resulted in increased pressure differential across perforation clusters, leading to effective diversion and maximum zonal coverage. Each stage was isolated using a bridge plug, and diagnostic pumping was conducted before each main treatment. To gain insight into the actual geometries achieved, data acquired during the treatment were history matched using a full 3D grid-oriented hydraulic fracture simulator and compared to initial simulations. Fracturing in extreme high temperature with high pressure poses significant challenges. This paper details successful hydraulic fracturing applications in one such reservoir regarding optimization and utilization of a fluid system to achieve optimum fracture geometries and minimizing formation damage and discusses other aspects of fracturing this reservoir, such as perforation strategies and operational tactics for successful placement of multistage hydraulic fracture treatments.

The Barik formation is a low-permeability conventional tight-gas reservoir, in Block 61 in the Sultanate of Oman, comprised of a series of interbedded sandstone and mudstone (shale) layers. To achieve the most efficient and economic development of this formation sequence, the wells require the application of massive hydraulic fracturing. Such an approach was developed and deployed during the Appraisal stage of the programme and a considerable effort was placed in ensuring that the fracture height was contiguous, resulting in an effective drainage across all layers of the Barik formation. This approach was then encapsulated in the Full Field Development (FFD) planning Basis of Design (BoD) and was established as the approach to be taken throughout FFD. Until the field development was well underway, a single fracture treatment had proven sufficient to stimulate the entire Barik reservoir. However, as the development moved into the Southern area of the field, a substantial thickening of the Barik sequence was encountered and with this change successful complete vertical propped fracture coverage became much more challenging to achieve in an effective and repeatable manner. This paper demonstrates the approaches that were subsequently taken with the fracture design, the fracturing fluid selection and the fracture perforation strategy to address this issue and restore the achievement of complete fracture/formation coverage. Throughout the paper a number of examples will be presented that demonstrate the issues and effects that arose with the thickening of the Barik formation. The paper will then go on to examine how these effects were identified, what surveillance was used and the various characteristics that were displayed and how they were inferred. It will examine how the various issues were addressed, what changes were made to the fracturing strategy and demonstrate, through direct results, the outcomes that were subsequently achieved. This paper will focus on some of the principal issues that can arise when moving a developing fracture BoD in a laminated sequence into a more thickly developed environment with more extensive height and bulkier sands. The paper will provide a number of detailed examples of the issues themselves, and describe the detrimental and impactful effects that they may have on fracture coverage and hence well productivity and EUR. Additionally, the paper will describe the approaches that can be used in order to successfully address these effects. The paper will clearly demonstrate that when such considerations are taken into account that a successful suite of outcomes can be achieved.

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.

Khazzan is a tight to low-end conventional gas field in the Sultanate of Oman. The target reservoir is a series of stacked sandstones with highly stressed, intercalated mudstones, which may provide baffles and barriers to vertical stimulation growth. Calibrated petrophysical and geomechanical models are integrated within stimulation models to provide high confidence in stimulation geometry. Radioactive (RA) Tracer logs have been used on key wells throughout the development to determine stimulation height growth beyond and within the perforated interval. Multi-stage stimulations deviating from the standard completion design may be required as the development covers an increasingly larger area. The calibrated stimulation models guide the completion design to ensure the resources are adequately stimulated. Sensitivities on gross thickness, reservoir quality and fluids are performed, along with the timing of the subsequent stimulations, to determine the optimum stimulation strategy. This enables the long-term stimulation strategy to incorporate the right design at the right point in the well lift to maximise the value. Additional insights into horizontal well completions strategies are gained. The completions petrophysicist provides a key integration point for the multiple disciplines involved in "geo-engineered completions".

Field "A" produces from a mixed-wet formation comprising of fine grained silicilite. The field is a sour light tight oil reservoir with permeability range from 0.001 – 0.1 mD, the only way to flow the existing vertical wells is through hydraulic fracs. Historically the wells have been fracced using water based frac fluids, which have caused severe negative consequences related to well integrity and reduced productivity. With a recovery factor of <1% after 15 years of production, the main challenge and objective lies in enhancing productivity and unlocking the huge volumes of this reservoir through optimizing the field development concept, completion, frac design and execution. A study was conducted with a recommendation to develop the field by drilling slanted wells with ~10 - 15 frac stages. The frac design in itself is unconventional or hybrid where the targeted frac half length is 5x more than the existing conventional ones. The use of oil based frac fluid instead of water is an opportunity actively pursued to enhance productivity and eliminate issues related to scale and corrosion that in the past have resulted in a loss of production. Findings of the study have clearly indicated that developing the field with several slanted multi frac wells is economically attractive; with an increase in Net Present Value (NPV) by ~60% and decrease in Unit Technical Cost(UTC) by ~30% compared to developing the field conventionally with vertical wells.

The objective of this work was to develop a supercritical CO 2 foam with a liquid phase composed of a polyelectrolyte complex nanoparticle system interacting with a viscoelastic surfactant solution. This is intended to be used as a fracturing fluid to reduce fluid loss and increase post-fracture clean-up efficiency for improved productivity in unconventional reservoirs. In a previous study, we optimized the polycation/polyanion ratio and polyelectrolyte pH using zeta potential and phase-angle light scattering. Rheological and foam stability tests were used to further optimize surfactant/polyelectrolyte ratio. In this work, dynamic fluid loss tests were performed on supercritical CO 2 foam generated using the optimized ratio of surfactant/PECNP to investigate the effect of PECNP addition to the surfactant solution on the fluid loss. The same foam systems were used to investigate post fracture clean up using sand pack tests. Interfacial tension was measured on both air-(surfactant/PECNP) and supercritical CO 2 -(surfactant/PECNP) systems to understand the effect of PECNP on IFT. Fluid loss to the formation during hydraulic fracturing causes water blockage, formation damage and capillary pressure shift, lowering the conductivity of the reservoir, and impeding the flow of oil and gas. Supercritical CO 2 foam generated by surfactant solution exhibited low fluid loss, thus lower values of fluid loss coefficient compared to unfoamed surfactant systems. However, addition of polyelectrolyte complex nanoparticles further reduced the total fluid loss and fluid loss coefficient. Foam fracturing fluids break in the presence of crude oil because the oil penetrates the foam lamellae causing drainage and lamellar rupture; this results in effective post fracture clean up using supercritical CO 2 foam as fracturing fluid. Foam systems generated by surfactant showed promising clean up results, and the addition of PECNP further increased clean up efficiency. From IFT test results we concluded that the addition of PECNP decreased interfacial tension of both air-(surfactant/PECNP) and supercritical CO 2 -(surfactant/PECNP) systems. The addition of optimized polyelectrolyte complex nanoparticles to surfactant in a supercritical CO 2 foam fracturing fluid can reduce interfacial tension and fluid loss, which will reduce formation damage, resulting in better hydrocarbon flow. PECNP stabilized surfactant-supercritical CO 2 foam drains rapidly in the presence of crude oil, leading to good clean-up, which will result in better flow back and higher productivity.

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.

The Amin formation is a tight sandstone formation, that is present in Block 61 in the Sultanate of Oman, that has presented a number of development challenges. The Amin reservoir is characterized by an average permeability approximately two orders of magnitude lower than the Barik formations, which is the other main current development reservoir within the field. Adding to the challenge is the presence of the immediately and extensively underlying Buah formation, which is known to be sour. During the Appraisal phase of the project, two vertical wells and one horizontal well were completed in the Amin, demonstrating that a horizontal well profile with multi-stage fracturing would most likely be required to achieve consistently commercial rates. It was also evident, even during the project sanction, that significant further investigation would be required to be able to more completely understand the hydraulic fracture behaviour in the Amin; in terms of the created fracture geometry, appropriate hydraulic fracturing methodology, suitable formation connection techniques, and other completion design factors to succeed with a reservoir development. Additionally, it was known that understanding reservoir fluid distribution would be fundamental to delivering such wells. During the Development phase several vertical wells were completed with a range of fracture types and designs, to facilitate an assessment of well performance in the vertical geometry, as well as understand the fracture height for various hydraulic fracturing techniques, including High Rate Water Fracturing (HRWF) treatments as well as Hybrid-Frac (HF) type approaches. Additionally, several horizontal wells were also completed to build upon the Basis of Design (BoD) that had been selected at the end of the Appraise phase, with a continuous learning approach taken to further develop the frac understanding. Lessons more recently learned from North American unconventional reservoir stimulations were also investigated, carefully selected and then subsequently applied in a coherent and systematic way. This paper presents a review of several of these vertical wells and two horizontal wells, attempting to demonstrate the progress made between the approaches. Additionally, the two horizontal wells will be used as a case study to illustrate the application of the continuous improvement methods, as well as the adoption of some key appropriate technologies transferred from North American unconventional reservoir stimulation approaches. These included an investigation of perforation cluster efficiency, the baseline fracture design and fracturing fluid types; as well as integrating directly with the open-hole characterization and production logs to enhance the frac designs and results.

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.

Post stimulation proppant flowback can be a serious problem after the hydraulic fracturing process and can cause a variety of issues like: reduced fracture propping resulting in decreased conductivity and hydrocarbon production;erosion related damage to surface and downhole equipment; and increased costs in dealing with recovered proppant disposal. To address the concerns related to proppant flowback, various technologies, including chemical, mechanical, and engineering design have been employed. A common and long term commercial approach is to apply a resin to the surface of the sand. However, resin coatings can be costly relative to the cost of the sand substrate, often doubling or tripling the cost of the sand substrate to which they are applied. Additionally, resin coated proppants often need to be activated with exposure to temperature and pressure. The requirement for additional chemical activators at lower reservoir temperatures can also add additional cost to the treatment. Furthermore, resin coated sands are typically manufactured near a sand mine and then shipped to remote well locations. This offers another layer of logistical complexity to bringing large volumes of sand to a site or often multiple types of sand and thus can add additional costs. In some cases, on-site or near-site manufacturing of resin coatings is possible, but again at an additional cost. A proppant flowback control measure which is cost-effective and can function over a wide range of reservoir conditions would be advantageous to the hydraulic fracturing process. A new technology for proppant flowback control was previously presented where chemically modifying the proppant surface with the proppant consolidation additive (PCA) can induce a strong capillary attraction among proppant grains leading to proppant agglomeration ( Lu et al., 2016 ). This study serves to further examine this sand surface modifying chemical. Additional experimental results will focus on conductivity measurement of surface treated proppant and flow resistance tests of treated proppants relative to untreated proppants at varying conditions. The field performance of more than 50 wells in western Canada in terms of proppant flowback control using thisnewly developed technology will also be presented. A discussion of field application and results in several scenarios will demonstrate the correlation of the laboratory experimental results to actual field performance. Compared with untreated either Tier 1 or Tier 2 proppant, the surface treatment of proppant increases flow resistance under all the tested confining pressure, also, noticeable increase of proppant conductivity under high confining pressure was observed, which is an advantage of the surface treatment of proppants. The field performance data show that this newly developed technology gives similar or better results relative to resin coated proppants in terms of proppant flowback control. This technology demonstrates the following advantages: 1) it can be applicable to either Tier 1 or Tier 2 proppant; 2) it can be easily applied on-the-fly to sand during a fracturing operation, either as the tail in sand stage, alternating during the entire stage, or being sprayed on all the sand stage, which makes it flexible for operators to design proppant flowback control and to ease the logistics of managing proppant delivery to location as well; 3) it perfroms under a wide range of reservoir conditions because it is independent of reservoir pressures and temperatures.

Throughout the development of major shale plays, a better understanding of stimulation influence on reservoir productivity has led to significant changes in industry completion practices. The relatively fast development of fields combined with the evolution of completion design suggests the completions performed on the earlier completed wells are understimulated and inadequate for optimum recovery. In the Eagle Ford and Haynesville shales, refracturing treatments were first performed using degradable particulate diversion, but yielded inconsistent results. However, a new method using the installation of a new casing string has been applied to these two separate plays to help reduce risk and maximize asset production. Precise placement of the restimulation treatment using degradable particulate diversion is complex because of a lack of treatment isolation. The fluid used in restimulation must overcome friction pressure differentials, the presence of several existing perforations, and reservoir depletion. Advancements in cement slurries and wellbore design have made it possible to install a new, smaller casing string into the existing wellbore and restore treatment isolation. Despite the tight annular clearances, a specialized slurry has been designed to maintain circulation and to provide good mechanical properties for proper zonal isolation. The reconstruction of the wellbore with the smaller casing string enables the refracturing treatment to be performed like new-drill completions by means of plug-and-perforate methodology. Although the treatment injection rate might be limited in comparison, many of the complications in diversion refracturing treatments are eliminated. This process has confirmed greater repeatability and more consistent production results across two separate plays. The successful implementation of 75 casing-in-casing refracturing treatments in the Haynesville resulted in an average estimated ultimate recovery (EUR) increase of approximately 150%. This technique has been implemented in the Eagle Ford and, although the number of wells in the dataset is fewer, the EUR of some wells observed have experienced an average increase of 140%. This method is becoming increasingly popular, with multiple operators successfully applying this technique throughout different portions of the Haynesville and Eagle Ford Shale.

Miqrat is a complex clastic deep tight gas reservoir in the North of the Sultanate of Oman. The Lower unit of the Miqrat formation is feldspatic sand characterized by low permeability not exceeding 0.1 mD and porosity up to 12 %. Based on results of the appraisal campaign of Field X, it contains significant volume of gas. However the production test data after fraccing showed mixed results. The objective of this study to explain the production behavior in relation to the frac geometry. Understanding the reason of possible overestimation of log derived Hydrocarbon saturation is important. Thus the interpretation of conventional and special logs was revisited. In parallel, all the available core data including SCAL and thin sections were dissected. Besides, the analysis of hydraulic fracture propagation, well tests, cement quality, PLT including Spectral Noise Log was performed. The wells were subdivided into categories according to their production. – wells producing no water – wells with water channeling from the water leg of Middle Miqrat – wells with transition zone intervals with two-phase inflow of water and gas. There are three main challenges that needed to be overcome. First challenge is to identify the high uncertainty in hydrocarbon saturation from the resistivity logs. Petrophysical evaluation shows that porosity profile derived from logs looks very similar in all wells with insignificant lateral variations. Hydrocarbon saturation estimated from logs looks also similar regardless of how deep or shallow the well is. However, production tests show different results, e.g. different flow rates and high water-cut are observed in some wells. The second challenge to keep the frac height below the boundary between Lower Miqrat and Middle Miqrat, which consist of around 3 to 7 meters of shale and in most of the field it is bound with water. The third one is to cover the upper part of the zone below the shale since it is the best part of Lower Miqrat without breaking to the water leg of Middle Miqrat. A geomechanical model was created and several frac model iterations were run since in the early appraisal well that boundary was broken. Investigation through multidisciplinary integrated team led to unlock the tight gas reserves in Lower Miqrat. Based on open hole log interpretation to create a geomechanical model. That model is being calibrated with DFIT, 3 different case hole logs and confirmed with production.