bluuebunny/crossref_metadata_2025_split huggingface dataset:
Systematic Engineering and Candidate Recognition Methodology for Stimulation in Depleted Fields leads to Multifold Increase in Production
Authors: Barasia A. , Pankaj P. , Venkateshwaran R. 
Published: May 2015

Abstract
Candidate recognition in mature brown fields and depleted fields for stimulation has always been a challenging task. It has become a common practice for many operators that when all else fails they turn to stimulating the well. The application of fracturing for any poor producer in a brown field does not guarantee success. Since traditional reservoir engineering methods like skin analysis via build-ups cannot be applied in these depleted reservoirs alternative techniques have to be used.
Identifying and stimulating key wells requires a systematic candidate recognition process with emphasis on the ability of the well to deliver post stimulation. Having a method to score completion and production integrity based on its petrophysical and geomechanical characteristics and thoroughly understanding the operating environment ensures a much better chance for these wells to be successful. Comprehensive candidate selection methodology with available data was devised to identify best stimulation candidates from existing set of wells. Comparative Petro-physical log evaluation, Mechanical Earth modelling and oriented perforations in selected wells was deployed to further understand reservoir and rock mechanical properties and limit surface pressures by minimizing near wellbore perforation and tortuosity effects.
Further to estimate economic viability; analytical modelling and Arps production decline was combined utilizing local learnings and experience to predict post fracture production. Full set of diagnostic tests was done to make a robust model that can simulate fracture propagation and help in optimizing fracturing design to place desired fracture in place. Post fracturing cleanup and well activation was closely monitored with design and recommendation on required Artificial Lift techniques as and when required. Production results achieved after applying this workflow exceeded initial expectations set by operator. Payout period achieved for total investment in this project was 75-150 days. Due to these encouraging results, same workflow was applied in number of depleted fields in Cambay basin with similar results.
This paper will summarize the workflow used for revitalizing production from some of the major fields including Candidate selection methodology, Petro-physical evaluation, Mechanical earth modelling, diagnostic tests for fracturing design, production forecasting, post fracture well activation and artificial lift design. In the end, possibilities of deploying this workflow for re-vitalizing other brownfields will be discussed.
The Implementation of State-of-the-Art Channel Fracturing Technique in High Permeability Layered Reservoirs in the Sinai Peninsula
Authors: Kortam Mostafa , Anwar M. , Mousa Doaa , Fouad Ahmed , Yosry Mohamed , Mathur Anil , Abbas Nelly Mohamed , Sahli Mohamed El 
Published: May 2015

Abstract
The Abu Rudies field in the Egyptian Sinai peninsula produces mainly from the South Gharib formation that is characterized as a complex, heterogeneous, thick and laminated, but permeable, slightly oil wet rock and depleted sandstones consisting of sands with an average permeability in the range of 150-550 mD and Young's Modulus in the order of 1.0 - 2.5 million psi. Conventional hydraulic fracturing and Frac & Pack techniques have been traditionally deployed to produce hydrocarbons and for sand control. The added complication is the reduction in the effective permeability to oil due to the rock being oil wet.
Conventional fracturing techniques have had limited success especially in the highly permeable compartments of the field due to premature screenouts that were encountered extensively, residual polymer in the intergranular porous rock and the flowback of formation sand and proppant.
This paper describes the application and production enhancement efforts for the first time with a novel channel-fracturing technique combined with rod-shaped proppant in selected production targets in the Abu Rudies field in Egypt. The channel fracturing technique introduces channels within the proppant pack that significantly increase conductivity and effective fracture half-length leading to increased productivity. Rod-shaped proppant when used as tail-in in fracturing treatments increases near- wellbore fracture conductivity and completely prevents proppant/formation sands flowback as demonstrated by zero flowback due to its particular geometry.
This paper describes actual case studies of fracturing a high-permeability layered reservoir using the channel fracturing technique, the problems encountered due to high leak off, low closure pressures, reservoir heterogeneity and the complexity due to adjacent water bearing layers. Finally, we demonstrate the well performance with the channel fracturing technique compared with alternate techniques.
A Case Study for Effective Perforation and Gravel Placement in a Complex Dual Casing Completion
Authors: Vigo Morounranti , Obanor Nelson , Munro Jock , Shumakov Yakov 
Published: May 2015

Abstract
Perforation performance can be greatly reduced when encountering multiple casings where depth of penetration and crucially reduced entrance holes prevent effective gravel placement. A practically proven case study is presented on the design, equipment selection and execution of a successful cased-hole gravel-pack campaign in dual casing completions of an injector well.
An integrated approach and workflow is implemented to enhance the gravel pack efficiency. It involves the combination of firstly, a high efficiency perforation system that optimizes tunnel geometry and penetration in a dual casing completion. Secondly, an innovative approach on the gravel pack installation using a viscous slurry to pump at slightly higher rates above the fracture gradient in order to create a small fracture around the wellbore. The success of the gravel pack installation is further assured by the application of an “alternate path” concept.
Packing the perforation channels is achieved by selecting a big-hole gun system that provided optimal performance through the multiple casings including highly phased large casing exit holes resulting in a large area-open-to-flow. The cased hole gravel pack completions is installed using a high rate gel pack technique creating short, highly conductive fractures enhancing connection of the reservoir to the wellbore. Furthermore, annular pack integrity is achieved using an alternate path design ensuring uniform gravel placement over the sizable reservoir interval. Injectivity into the formation is proven via constant tubular and annular pressure; indicating minimal permeability impairment to the formation. The production zone is flow tested using an electric submersible pump with trace of solids 0.01% WT received at surface confirming the integrity of the gravel pack completion.
With the increase of more complex reservoirs and completion techniques, practical application and solutions of such complexities add to the industry knowledge base. This paper shares a practical and proven integrated approach to providing solutions for installation of gravel pack in a dual-completions. This concept is based on many years of operational experience and lessons learned on the field.
A Non-Damaging Polymer Fluid System for Conventional and Unconventional Formations
Authors: Wang Xiaolan , Sun Hong , Zhou Jia , Guerin Michael , Li Leiming 
Published: May 2015

Abstract
Most conventional fracturing fluid systems are based on guar and guar derivatives. Therefore, fracturing costs are strongly influenced by guar price. In addition, when pumped in unconventional formations, these fluid systems can cause significant formation damage due to insoluble protein components in guar. While Polyacrylamide (PAM) based copolymers are often used in unconventional formation stimulation, they are often considered to be hard to break.
A possible solution that can mitigate the problems associated with the conventional fracturing fluid systems is a new fluid system based on a carefully designed synthetic polymer. The synthetic nature of the polymer translates into a stable operating cost without being impacted by market fluctuations like in the case of guar. This new synthetic polymer system is crosslinked and applied similarly to polysaccharide-based fluids. To alleviate concerns that synthetic polymer is hard to break, this polymer incorporates special linkages, periodically distributed along its backbone, to make it easily broken into small fragments with conventional oxidative breakers under downhole conditions to leave minimal formation or fracture damage. The polymer also incorporates functional groups that resist damage from water hardness. In addition, the polymer hydrates almost instantaneously and allows rapid viscosity generation and adjustment without a hydration unit, which greatly reduces footprint of hydraulic fracturing treatments.
While this new polymer system can be used in slickwater hydraulic fracturing and linear gel applications, laboratory testing also showed that it can be effectively crosslinked with conventional metal crosslinkers. This paper investigates the possibility of using this new polymer as a total package to be applied throughout hybrid fracturing operations for tight formations besides using it as fracturing fluids for conventional formations. Laboratory work also investigated other applications of the new polymer such as acid gelling, acid fracturing, and diversion, to name a few. This paper presents the laboratory performance and the underlying mechanisms of the novel polymer fluid system.
Wellsite Mineralogical Data Acquisition; Understanding Results from Multiple Analytical Sources
Authors: Davis Brian "BJ" , Koch Amber , Braun Gerald , O'Connor Cassie , Frost Elton , Quinn Terry , Ly Chi Vinh , Oliver Guy , Spence Graham , Whatley Bill , Cardy Neil , Wilson Michael 
Published: May 2015

Abstract
Technological advances in both equipment and computer software have enabled the implementation of new approaches in generation of mineralogical datasets at petroleum wellsites. These datasets are currently utilized by hydraulic fracturing engineers to assist in designing optimized fracture stage intervals in horizontal wellbores, rather than using evenly spaced intervals between treatment stages. Mineralogical data is generated by downhole wireline logging tools, and on drill cuttings, conventional wholecores, and rotary sidewall coreplugs utilizing a variety of analytical instrumentation techniques. This paper documents a study undertaken to assess mineralogical datasets generated on comparable samples, focused on evaluating analytical limitations and variances, toward obtaining consistent mineralogical results.
Instrumentation typically used to generate these datasets include x -ray diffraction (XRD), x-ray fluorescence (XRF), scanning electron microscopy-energy dispersive spectroscopy (SEM-EDS), fourier transform infrared spectroscopy (FTIR), and inductively coupled plasma techniques (ICP mass spectroscopy or ICP optical emission spectroscopy). Variables introduced into the analysis in addition to the different analytical techniques include sample types and sizes, sampling methods, sample preparation, drilling mud contaminants, lithological heterogeneity, and depth correlations between cuttings, cores, and wireline measurements.
As the study evolved it became clear that wellsite sampling and preparation protocols needed to be properly defined to assure sample quality and accurate sample depth reference. Analytical equipment limitations must be fully understood, as should differences in measurement technologies both in the laboratory and at the wellsite. Equipment destined for wellsite analysis was evaluated in a controlled laboratory environment using reference mineral standards and standard mixtures to understand testing limitations and refine mineral phase calculations. Mineral terminologies, classifications, compositions, and the resulting databases were reviewed for consistency. Multiple cuttings and core sample sets from conventional sandstones, carbonates, and current mudrock plays such as the Eagle Ford and Marcellus shales were sub-divided and analyzed to allow direct comparisons of generated datasets. Complementary testing was conducted to confirm data quality.
This study yielded increased confidence in wellsite and laboratory analyses, including caveats where necessary, procedural guidelines for each analytical technique, and verification of deliverables appropriate to unconventional mudstone reservoirs. Example datasets, graphical comparisons, and report formats are included. The resultant wellsite datasets, in tandem with additional wellsite analytics, enhance confidence in optimized fracture stage interval decisions.
The Effect of CO2 Gas Flooding on Three Phase Trapping Mechanisms for Enhanced Oil Recovery and CO2 Storage
Authors: Peksa A. E. , Wolf K.-H. A. , Daskaroli M. , Zitha P. L. 
Published: May 2015

Abstract
Release of CO2 as a by-product of industrial and domestic operations around the world is undesirable due to its negative impact on the environment climate. As an option for reduction many efforts are made to develop methods for the capture and storage of CO2. One potential option, the CO2 enhanced oil recovery (CO2-EOR) technique, is already in use for decades and widely accepted as a promising solution for mobilization and recovery of residual oil in water wet rock. It is also a mitigation prospect for CO2 reduction and an opportunity for permanent storage after the production stage. For better understanding of the mechanisms controlling the oil displacement and CO2 sequestration, the interaction between pore system, flow and phase equilibrium were conducted in a series of CO2 flooding experiments. As an improvement, we propose to inject CO2 as a 2nd stage EOR action after water flooding and accurately monitor and measure CO2 in the system.
The experimental part involves brine injection into vertical positioned cylindrical Bentheimer sandstone (BS) cores at residual oil saturation, which mimic depleted oil reservoirs. Next, CO2 is injected at the bottom side of the column to recover oil and to trap CO2. The trapped and residual saturations are measured by mass balance and visualized by a CT - scanner during the experiment to discriminate different phases through time. The oil recovery and trapped saturations of oil and gas are determined as functions of initial oil and gas saturation.
Different from previous experimental studies, a continuous CO2 injection technique was used for coupled CO2 sequestration and EOR. The experiments show for CO2 flooding experiments an increase in the back pressure between tests that result in higher CO2 storage and in higher oil recovery. The laboratory results are used for upgrading and building of a model for three phase flow in sandstone reservoir.
This paper gives a better understanding of three phase trapping mechanisms and shows results on gas phase behavior with various injection flow rates. In addition, we assess whether the flow and pressure schemes are feasible and we show prospective recoveries and storage efficiency. The experimental results help to improve up-scaling conditions for recovery at field scale.
Mechanical Properties and Natural Fractures in a Horn River Shale Core from Well Logs and Hardness Measurements
Authors: Yang Sheng , Harris Nicholas , Dong Tian , Wu Wei , Chen Zhangxin 
Published: May 2015

Abstract
This paper addresses factors that influence rock mechanical properties and the development of natural fractures of Horn River Group, a major shale gas play, using cores and well log data of well Maxhamish D-012-L/094-O-15. The majority of natural fractures in the Horn River shale are narrow fractures, sealed with carbonate mineral. In this study, the formation of observed fractures is primarily determined by the lithology type, mineral composition, bed thickness, the lithology of the surrounding bed and the rock mechanical properties. The different cement types in the fracture aperture also control the fracture reactivation by hydraulic fracturing.
Brittleness is one of the most important mechanical properties controlling fractures formation, because brittle shale is more easily fractured than ductile shale and fractures in brittle shale tend to perpetuate when the fracturing pressure is released. In this study, a hardness value measured by the Equotip Bambino 2 hardness tester is found to be a good proxy for the brittleness of shale layers. The hardness measured an Equotip Bambino 2 hardness tester and the brittleness calculated from well logs show a good correlation. An orthogonal regression method is applied to deeply investigate their relationship. For different members of the Horn River Group, the correlation relationship is different, which is mainly affected by the changes of the Si and Ca mineral content. As shown in this paper, the hardness measured by an Equotip Bambino 2 is a good indicator of the log-derived brittleness, because of its high resolution and more accuracy. A hardness value is also more sensitive to the mineral composition changing than a brittleness value. Based on a statistical analysis, the hardness more accurately predicts the distribution of natural fractures, so that when a hardness value is over 550, natural fractures will be developed. These relationships can also be used to predict natural fractures and the targets of hydraulic fracturing when dipole sonic and density well logs are not available.
Pore-Level Experimental Investigation of ASP Flooding to Recover Heavy Oil in Fractured Five-Spot Micromodels
Authors: Sedaghat M. , Mohammadzadeh O. , Kord S. , Chatzis I. 
Published: May 2015

Abstract
Although Alkaline-Surfactant-Polymer (ASP) flooding is proved to be efficient for heavy oil recovery, the displacement mechanisms/efficiency of this process should be discussed further in fractured porous media especially in typical waterflood geometrical configurations such as five-spot injection-production pattern. In this study, several ASP flooding tests were conducted in fractured glass-etched micromodels which were initially saturated with heavy oil. The ASP flooding tests were conducted at constant injection flow rates and different fracture geometrical characteristics were used. The ASP solutions constituted of five polymers, two surfactants and three alkaline types. The results showed that use of synthetic polymers, especially hydrolyzed polyacrylamide, with high molecular weight as well as cationic surfactant increases the ultimate oil recovery. In addition, location of the injection well with respect to the fracture system plays a significant role in the performance of the ASP flooding. For instance, an increase in the angle associated with the longitudinal extension of fractures with respect to the main flow direction resulted in enhanced oil recovery and also postponed the wetting phase breakthrough time. Mechanistic study of this displacement process revealed that dispersive and diffusive behavior of ASP front enhanced the fluid transport from fracture to matrix as well as increased the microscopic displacement efficiency, which both were more pronounced for the case of longer fractures. In addition, emulsification and coalescence mechanisms are responsible for ASP frontal advancement as well as flow of the ASP phase in the invaded portion of the models. Residual oil in the invaded region, which was observed in the form of discontinuous oil ganglia dispersed in the invaded pore bodies or in the form of pendular bridges formed around some of the solid particles, was mobilized in the form of oil wads through the droplets of the displacing phase. In this study, the mechanisms responsible for recovery of the in-situ oil by ASP flooding were mechanistically investigated along with quantitative parametric study on the effect of different fluid/porous media properties on ultimate recovery factor.
A Water Swelling Polymer for Fracture Shutoff to Improve Injection Profile During Secondary Recovery: Case Histories and Lessons Learned After More Than 600 Well Interventions
Authors: Vasquez Julio , Rodriguez Levi 
Published: May 2015

Abstract
Nonmatrix reservoir features, such as fractures, fissures, karsted zones, and/or eroded out permeability zones, can detrimentally affect injection profiles and sweep efficiency of secondary recovery techniques, such as waterflooding. Current available technologies, including conventional cement squeezes, foamed cement treatments, resins, or temperature-activated low- to medium-viscosity polymer gel systems etc. present limitations to plugging these undesired features because of their inability to withstand influxes of water in a fractured environment, which can cause dilution of the materials and prevent them from activating/curing. This paper presents the field implementation of a water swelling polymer (WSP) for fracture shutoff to help improve the injection profile to overcome such challenges. Case histories are discussed highlighting the diagnostic stage.
The WSP system is capable of absorbing up to 400 times its own weight in water. The rate of absorption can be controlled based on salinity of the carrier fluid. As the WSP enters the nonmatrix reservoir features, the systems begin absorbing water, expanding, and filling this “empty” space. Most of the WSP treatments are mixed on-the-fly and bullheaded into the wellbore as it will not invade the rock matrix because of particle size. Treatments are usually pumped in stages because the fracture, void, or fissure capacity is unknown. Ideally, placement of the WSP system should reflect an increase to pressure, which is an indication that the fracture system has received a sufficient treatment volume to fill the void space and subsequently achieve diversion of the injection fluid. The WSP particle size varies from 40 μm up to 4 mm. This system remains stable in H2S and CO2 environments.
This water swelling polymer presents an innovative technology for fracture, fissure, and highly eroded out permeability shutoff to help improve sweep efficiency of water, gas, and water alternating gas (WAG) injection. In addition, this conformance technology is also applicable to loss circulation problems while drilling and performing casing repairs. A variety of case histories are discussed in detail in this paper. To date, more than 600 treatments have been performed using this technology.