bluuebunny/crossref_metadata_2025_split huggingface dataset:
Multistage Hydraulic Fracturing Campaign Learning Curve in a Tight Sandstone Reservoir, Offshore West Africa
Authors: Sedda P.. , Parziale S.. , Giammancheri M.. , Forno L. Dal , Ferdinandi F.. , Farina L.. , Tsangueu B. E. , Giraud C.. , Morbelli D.. , Mauth K. D. 
Published: October 2018

Abstract
In the last decade, hydraulic fracturing has been successfully applied in West Africa for the development of tight reservoirs. Since 2007, more than 200 fracturing stages have been achieved in 9 different fields targeting wells characterized by a wide range of conditions: from sandstone to carbonate formations, from low to high temperature reservoirs, and from old existing completions to new drilled wells.
While applying this technology throughout the years, tailored solutions for treatments design have been continuously put in place to address the observed challenges and maximize the final oil recovery. The deployment of new technologies such as proppant flowback prevention additives, non-radioactive tracers for fracture height monitoring, and channel fracturing, to boost the fracture conductivity played a major role in achieving the desired results.
The accumulated in-depth knowledge on hydraulic fracturing built from local experience allowed Eni West Africa to rapidly approach a new offshore tight oil field development with confidence that hydraulic fracturing would be an effetive stimulation technique. This paper will describe the fracturing campaign major milestones, from the promising results obtained on the exploration wells, to the optimization actions implemented during the first development phase. Thus far, six horizontal and two vertical wells were completed, including a total of 23 hydraulic fracturing stages during a single campaign spanning less than one year.
On the first of the two vertical wells, each stimulated with a single frac stage, a non-radioactive tracer was employed for measuring the propped fracture height, and calibrating the frac model. For the horizontal wells, where 3 or 4 frac stages were implemented, a plug-and-perf (P&P) technique was selected. This method included coil tubing equipped with fiber optic, enabling precise perforation intervals placement, also providing flexibility in case re-perforation was required. Moreover, several actions were adopted to improve completion efficiency and cost-effectiveness, including perforation selection to limit near-wellbore pressure losses, and coiled tubing runs optimization for setting the bridge plug and perforating in a single trip.
Finally, particular focus will be given to the steep achieved learning curve, describing the adopted decisions, to improve both completion performance and fracture conductivity.
Fracture Design and Placement and Its Application and Influence on Amin Performance
Authors: Ishteiwy O. A. , Dawson W.. , Al Shidhani R.. , Al Busafi B.. 
Published: October 2018

Abstract
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.
Successful Application of TSE-Based Fracturing Fluids in Proppant Fracturing for Unconventional Carbonate Source Rock
Authors: Al-Taq Ali A. , Al-Khaldi Mohammed H. , Alfakher Basil M. , Mechkak Karim 
Published: October 2018

Abstract
Fracturing operations consume relatively large amounts of fresh or groundwater, especially in the area of unconventional resources where multi-stage fracturing is required to obtain an economical production rate and improve recovery. In an attempt to conserve groundwater, treated sewage effluent (TSE) has been evaluated and optimized for fracturing treatments to provide the required transport property for the proppant and not induce formation damage by maintaining compatibility with formation brine. Extensive laboratory work has been conducted including viscosity measurements, compatibility testing, and a microbial study to optimize an TSE-based fracturing fluid for unconventional operations. Based on laboratory recommendations, the TSE-based fracturing fluid has been applied successfully on well-A.
Twenty stages of unconventional proppant fracture stimulation utilizing the Plug and Perf (P-n-P) technique across the carbonate source rock have been applied successfully. Two base fluids, freshwater and TSE, were used to evaluate the effectiveness of TSE as a substitute for the freshwater in unconventional fracturing operations. Each water was used in 10 stages. The post-fracturing production results of well-A showed comparable results with the offset wells treated only with freshwater-based fracturing fluids. The pressure logging tests (PLT) conducted on this well confirmed that contribution of intervals treated with TSE-based fracturing fluid was comparable with those treated with fresh water-based fracturing fluid. There was no evidence of scaling issues during the flowback period for both fluid systems. Microbial evaluation of water samples collected during the flowback of well-A showed no presence of bacteria in these samples. This paper will discuss the laboratory work and the field application of TSE-based fracturing fluid.
ACA Practical Considerations: When is it Accurate and How Should it be Used to Improve Reservoir Stimulation
Authors: Ishteiwy O. A. , Jaboob M.. , Turk G.. , Dwi-Kurniadi S.. , Al-Shueili A.. , Al-Manji A.. , Smith P.. 
Published: October 2018

Abstract
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.
Unconventional Multiplay Evaluation of Casing-in-Casing Refracturing Treatments
Authors: Cadotte R. J. , Elbel Brittany , Modeland Neil 
Published: October 2018

Abstract
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.
Development Strategy Optimization of Ning201 Block Longmaxi Shale Gas
Authors: Yong Rui , Wu Jianfa , Shi Xuewen , Zhuang Xiangqi , Wen Heng , Luo Yin 
Published: October 2018

Abstract
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 15×108 m3/a production capacity. During early appraisal phase before 2014, average testing results of wells were 10~15×104 m3/d. In the end of 2016 and early 2017, average testing results of large numbers of wells across multiple pads achieved over 25×104 m3/d. Overall testing results of some pads have exceeded 180×104 m3/d per pad, and some of them may exceed 180×104 m3/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.
Investigation of Multiple Hydraulic Fracture Propagation for Low-Pressure Tight Sandstone Reservoirs in Northern Ordos Basin of Changqing Oilfield, China
Authors: Tang Jizhou , Ehlig-Economides Christine , Li Jiawei , Guo Xuyang , Wu Kan , Mu Lijun , Tang Meirong , Du Xianfei 
Published: October 2018

Abstract
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.
Coupling Geomechanical Effects and Reservoir Dynamics for Modeling Rejuvenation in Unconventional Plays
Authors: Dutta R.. , Pinto R.. , Flores J. C. , Stolyarov S. M. , Yang J.. 
Published: October 2018

Abstract
An integrated understanding of geomechanical effects, fracture propagation and reservoir dynamics is critical in the efficient and cost-effective application of rejuvenation technologies for unconventional plays. While various reservoir models depicting the hydraulic fracturing process are available in the industry, many tend to be simplified or do not capture the numerous parameters that affect both the initial and restimulation processes. This study takes a further step towards building a more realistic picture of fracturing in unconventional plays. In particular, a workflow is presented to couple the geomechanical effects and reservoir simulation modeling in unconventional plays. The objective is to make use of the learnings from this modeling in the successful application of rejuvenation technology.
The integrated model is developed using existing horizontal unconventional wells in a US shale play. During the initial phase of hydraulic fracturing, variations in stress occur both during injection and production periods. These stresses affect the growth of the fracture and its consequent fracture geometry. While employing various rejuvenation technologies, the ability to re-stimulate the rock will depend on a combination of factors, two primary ones being stress variation and pore-pressure depletion. These effects are incorporated into the reservoir model. Consequently, the production history-matched reservoir model incorporates pressure-dependent permeability variation as well as capillary pressure to account for varying reservoir dynamics.
Results from this study highlight the importance of changing stress regimes on fracture geometry and its consequent impact on production. We present a methodology to integrate geomechanical effects into a reservoir simulation model. The study also indicates the importance of treatment fluid volumes pumped at various stages during the refracturing operation.
Additional benefit of restimulating a well will vary from one well to another. The benefit is realized in terms of cumulative fluid volumes and reservoir contacted. The modeling techniques presented may help in application of such restimulation operations based on its impact on recoverable reserves. In summary, this study shows that a comprehensive understanding of stress changes coupled with reservoir dynamics will help better plan the application of various rejuvenation technologies.
Sweet and Sour Fracturing : The Impact of Post-Fracture Clean-Up on H2S and the Reservoir
Authors: Al-Manji A.. , Al-Shueili A.. , Orjuela L.. , White D.. , Kurniadi S. D. , Rylance M.. 
Published: October 2018

AbstractThe Barik formation is a tight low-permeability conventional gas reservoir in the Sultanate of Oman comprising of a series of interbedded sandstones and shales. To achieve an efficient and economic development of this formation, the wells require the application of massive hydraulic fracturing operations, in order to achieve the required surface area and connectivity for production delivery.Hydraulic fracturing operations often involve the use of a wide range of chemical components and the industry has understood for some time that chemical reactions take place both during and after fracture treatments have been performed. Post fracture treatment a wide range of differing chemical effects can take place and this may continue for some time during the extensive flowback and clean-up period. Such chemistries can result in a range of differing effects, including unplanned scaling tendencies, corrosional behaviour and can even influence aspects such as hydrate control. Such effects can also have an adverse impact on the well itself, the surface manifolding/valves, gathering system and production facilities and need to be well appreciated in order to remove issues.During the early Appraisal of the Barik formation, in Block 61 in the Sultanate of Oman, H2S had been observed during the post-frac well-test operations. However, the Barik reservoir within the Khazzan field, was believed to be sweet and not reflect a measurable H2S; a characteristic that had been confirmed by performing pre-frac openhole sampling. As had been determined with fracturing operations elsewhere, it was surmised that the frac operations themselves where the potential source of the H2S. Potential causes for this included thermal decomposition of fluid chemistry as well as inadvertent contamination of original source water used for the feed fluid. It had been observed/measured, that the magnitude of H2S reduced with time and was directly related to fracturing fluid clean-up. After extensive investigation the evidence suggested that the root-cause was a combination of the presence of a hardy Sulphate Reducing Bacteria (SRB) species along with the presence of a thiosuplhate feedstock in the frac fluid.This paper will present a full, robust and coherent analysis of the presence of H2S, the rigorous steps that were followed to identify the root-causes and the identification of potential sources/causes. The paper will present the preventive measures that have been taken and their impact on the overall temporary levels of H2S that have been seen in the operations since. The paper will go on to recommend that for future operations, particularly start-up areas, as transitory levels of H2S might not be identified, not because H2S is not there but rather that there is typically no apparatus nor sufficiently accurate surveillance in place on everyday operations to precisely identify such material.