bluuebunny/crossref_metadata_2025_split huggingface dataset:
Visual Investigation of Oil Recovery by Low Salinity Water Injection: Formation of Water Micro-Dispersions and Wettability Alteration
Authors: Emadi Alireza , Sohrabi Mehran 
Published: September 2013

Abstract
Low salinity waterflood (LSW) is a relatively new enhanced oil recovery (EOR) technique which has been reported to improve oil recovery in several laboratory experiments and some field trials. The general assumption among researchers is that LSW shifts wettability towards a more favourable state for oil recovery. Several hypotheses have been introduced in the literature as possible mechanisms involved in oil recovery by LSW e.g. fine migration and flow diversion, multi-component ion exchange (MIE), and rise in pH. However, a consistent theory to explain the process of wettability modification has not yet emerged.
This paper presents the results of a comprehensive set of direct visualization (micromodel) experiments which investigate the low salinity effect (LSE) from a novel perspective. The visualization study, using reservoir-condition micromodels, shows that when low salinity brine comes in contact with certain crude oils, a large number of water micro-dispersions form at the oil/water interface within the oil phase. The formation and precipitation of these micro-dispersions can only be seen under high magnifications using our imaging system specifically designed for thin micromodels. The water micro-dispersions do not form when the oil is in contact with a high salinity brine and when they form due to low salinity of the brine, they coalescence as soon as the oil comes in contact with a high salinity brine.
In our micromodel tests, when a mixed-wet micromodel and high salinity connate water were utilized, the formation of these micro-dispersions was associated with a slight change in the wettability and redistribution of fluids. We hypothesize that formation of the micro-dispersions results in additional oil recovery through two separate mechanisms; (1) depletion of the oil/water interface from natural surface active materials, resulting in wettability alteration and, (2) swelling of droplets of high salinity connate water. The results of this study introduce water/oil interactions and formation of water micro-dispersions as a potential mechanism for wettability alteration and improved oil recovery in low salinity water injection.
Modeling Water Flow in Hydraulically-Fractured Shale Wells
Authors: Jurus Wojciech J. , Whitson Curtis Hays , Golan Michael 
Published: September 2013

Abstract
This paper provides an approach to model water injection and production performance observed in horizontal multi-fractured wells using a commercial finite difference (FD) model. Stress dependent permeability is used to ensure that injected rates and volumes during hydraulic fracturing are predicted by the FD model. Varying degrees of water retention observed in shale wells is modeled using gas-water imbibition capillary pressure.
Hydraulic fracturing is used to stimulate shale and other ultra-tight reservoirs. During the treatment tens of thousands barrels of water are injected into a single well, distributed between many (5-30+) fractures. Field experience shows that a significant fraction of injected water never flows back, and the amount depends somewhat on how long the well is shut-in prior to production start.
This study was conducted using a commercial black-oil reservoir simulator. A horizontal well with multiple transverse fractures is modeled. A simple stress dependent permeability model (without hysteresis) has been found to provide sufficient permeability increase during injection to ensure the magnitude of injected water rates and volumes achieved during actual fracturing operations.
Inclusion of water imbibition capillary pressures helps control the amount of water retained by the rock after injection. Capillary forces redistribute injected water further into the rock than if capillarity is ignored. When a well is shut-in prior to flowback, imbibition draws injected water yet further into the rock, reducing water mobility and total recovery of injected volumes when the well starts producing. We study water flowback behavior as a function of water imbibition capillary pressure curves: their magnitude and shape (pore size distribution and wettability).
The mobility of water, as given by relative permeability curves, has an impact on water imbibition and distribution of water in the shale formation near the fracture. It affects the rate of water flowback, but it has a limited effect on total water recovery. We also considered situations with the shale formation initially void of water ("dry" shales), where we find that water recovery is reduced.
Modeling the flow of water in horizontal multi-fractured wells is important to estimate water loss and recovery and the impact on flow performance of hydrocarbons.
Development of Brittle Shale Fracture Network Model - Part 2: What is the Value of SRV?
Authors: Nejad Amir M. , Shelley Robert F. , Lehman Lyle V. , Shah Koras , Gusain Deepak , Conway Matthew T. 
Published: September 2013

Abstract
This paper discusses the workflow for developing a model to predict gas production for hydraulic fracture stages in a brittle shale environment. In our last paper (SPE 163829), we developed a model to predict fracture network geometry (width, length, and height) obtained from microseismic data for various fracture treatment designs. In this study, using both microseismic data and fracture/completion data; frac treatment production is estimated. The well database used for this purpose is comprised of fracture design parameters including treatment volumes, rates, proppant mass and size; well properties include perforation interval length, and perforation depth.
The goal of this study is to provide insight into factors affecting well production in a brittle shale environment. Initial data screening demonstrated massive data scattering and as a result data mining techniques are employed to find possible hidden relationships to explain the nature of the data. Also, using sensitivity analysis on the predictive model, improvements in the current fracture designs and completion schemes in Barnett shale are made.
The database is examined from different aspects using various data mining approaches. After screening and preprocessing the data, non-process affected outlier wells are removed from the dataset. Then, a forward predictive neural network model is trained with fracture design and well data parameters as inputs and well cumulative gas production per stage as outputs. Neural networks are trained with the help of genetic algorithm (GA). The sensitivity study on the trained network provided many insights about well completion and stimulation strategies. Recommendations on how to improve fracture designs and well completion schemes are provided based on sensitivity analysis on the neural networks. Results of neural network modeling in Barnett shale are compared to other gas producing shale assets such as Fayetteville and Haynesville shale to compare the findings.
The results of this work potentially help understanding of completion and fracture treatment designs on well productivity in gas producing shale assets. This will potentially help operators understand how to more effectively design frac treatments and/or reduce the operational costs associated with well completion in a brittle shale environment. Considering the fact that the relationship between stimulated reservoir volume and production is not entirely understood, this work may shed some lights on the aforementioned issue.
Evolution of Dual Fuel Pressure Pumping for Fracturing: Methods, Economics, Field Trial Results and Improvements in Availability of Fuel
Authors: Seybold Elle , Goswick Sam , King George E. , Erickson Brian , Bahorich Mike , Bruchman Mark 
Published: September 2013

Abstract
The displacement of a significant amount of diesel fuel with natural gas during large scale fracturing and drilling developments can be economically feasible in many cases with minor modifications to most diesel engines using dual fuel technology. Dual fuel describes the combination of a pressure and volume regulated stream of natural gas flowing through the engine intake and mixing with a reduced amount of injected diesel fuel in the engine to create power output that is nearly indistinguishable from using straight diesel fuel in high pressure fracturing pumps and other support equipment. Combining diesel fuel and natural gas in a dual fuel system reduces emissions of NOx, SOx, CO2, VOCs and particulates.
Diesel fuel volume has been reduced by as much as 1,575 gallons per frac stage in field testing (63% of total fuel). Engine modification is with primarily bolt-on aftermarket and factory kits. Fuel savings vary depending on price and availability of the natural gas fuel source: LNG (liquid form) from existing liquefaction and/or storage infrastructure or CNG (gaseous form) from local distribution companies (LDC), and/or field gas or distribution gas pipeline systems. Learnings presented from field trials include a case history of frac jobs using CNG, LNG and other gas supply. Economic data is presented on the overall process. Recognition that availability of adequate CNG and LNG fuel supplies may be limiting expanded implementation of dual fuel technologies has prompted us to consider methods of making both fuel supplies more available to other industrial segments as well as the oil and gas industry.
Oil Recovery Enhancement in Mature Reservoirs Using Innovative Horizontal Well Placement and Evaluation Strategies - An Example from South China Sea
Authors: Luo D. , Li L. , Tao B. , Denichou J. M. , Halomoan P. M. , Bisain A. S. , Wang C. 
Published: September 2013

Abstract
Located in offshore South China, Panyu oil field has entered into mature development phase after a decade of intensive production. A new horizontal wells campaign has resumed since 2012 targeting the remaining thin oil column reserves that are being squeezed by strong bottom water drive. The fluid contacts are highly uncertain in the current reservoir state. After a review of the technical and geological challenges encountered during the project, this paper will feature the successful approach taken to optimize remaining reserve recovery using innovative horizontal well placement strategies. The how-to-execute of these strategies will be detailed through the description of various cases encountered. This includes landing the wells with very low incident angle - less than 2 deg at the top of the reservoir - and drilling the lateral sections within a very small target window (2 ft) below the reservoir top, which both require rigorous geological well placement and control. In addition, the authors will describe how during the thorough planning phase, the team has selected to use directional electromagnetic and wellbore imaging technologies for proper well placement, reservoir profiles description, and current OWC level identification.
The team has observed that the application of these integrated strategies and technology solutions have helped to:
Eliminate the needs for pilot-hole wells and contributed to the improvement of the drilling efficiency by keeping the trajectory within the reservoir, avoid unnecessary adjustments, and avoid the sidetracks, thus significantly save the AFE budget. Minimize attic oil, thus optimizing the remaining reserve recovery. Optimize the outline of future horizontal drains locations.
The performance of the horizontal wells drilled up to date – and placed extremely close to the reservoir top – shows that each of them has produced from 2000 to 6000 bopd with zero to very low water cut. A reversing production trend from the decline to positive growth is also recorded. Six months after the first horizontal well inception in September 2012, the cumulative incremental oil of the field has reached 2.1 million barrels or 45% higher than forecast. The successful implementation of the new development strategy and the application of fit for purpose technologies in highly mature oil fields have led to sustained and extended production, increasing the ultimate recovery and asset economics.
Step Change Drilling Technology Modifies Drill String Dynamics and Results in Reduced Drilling Vibrations
Authors: Gaines M. , Morrison RD. , Herrington D. 
Published: September 2013

Abstract
Through the years, significant advancements have been achieved with respect to well design, depths drilled, and overall drilling efficiencies. However, in spite of all of these advancements, one major consistent challenge facing the drilling community is the prevalence of downhole vibrations, with specific emphasis on lateral vibrations and shocks.
These lateral shocks can be attributed to numerous drilling environmental challenges, and with the exponential increase in long reach laterals, well profiles, and formation changes, the increase in potential for significant shocks to cause damage to key bottom hole assembly (BHA) components is increased as well. To mitigate potential BHA damage, increase ROP, and provide a significant increase in bit life, a novel technology has been developed to tackle these challenges.
This vibration dissipation and mitigation tool has proven performance in both land and offshore applications, providing marked improvements over previous conventional solutions. When using this technology in the Gulf of Mexico, ROP improvements yielding an excess of 50% as well as a substantial stick slip reduction were observed, ultimately reducing time drilled and overall drilling costs.
The application of this innovative vibration mitigation and reduction technology is unique, especially in comparison to conventional solutions seeking to reduce vibration. Rather than seeking to simply absorb vibrations caused by drill string dynamics as with conventional solutions, this technology seeks to actively change the dynamics of the drill string to prevent these vibrations from ever occurring while offering a system for dissipating the residual vibrations. As this paper will demonstrate, this new technology has proven to successfully provide more control to the driller in applications once thought to be without a solution to such vibrational challenges.
This paper will discuss the advantages of this formative technology along with providing case history and accompanying supporting run data to quantify the performance of this innovative technology.
Magnitude-Based Calibrated Discrete Fracture Network Methodology
Authors: McKenna Jonathan P. 
Published: September 2013

Abstract
Effective propped fracture half-lengths following a typical hydraulic fracture stimulation of a wellbore can be difficult to quantify. Therefore, new modeling techniques must be developed to make estimates of proppant distribution in a formation to understand the spatial extent of proppant-filled fractures. The distribution of propped and unpropped fractures can then be statistically analyzed to determine the productive stimulated rock volume (SRV) and constrain key field development parameters such as wellbore and stage spacing as well as vertical containment of proppant placement.
A magnitude-based calibrated Discrete Fracture Network (DFN) methodology based on microseismicity induced during stimulation of a wellbore has been developed that incorporates magnitude of the event (and associated microseismic moment (M)), rock rigidity (μ), injected fluid volumes (Vi), and fluid efficiency (η). Calculated fracture volumes (Vf) are then scaled to account for any missing portion of the seismic population. The calibrated DFN can then be filled with the measured injected proppant volume on a stage-by-stage basis by initially filling fractures nearest the wellbore and systematically filling fractures outward from the wellbore until all deposited proppant volumes have been depleted.
Fundamentally, for every microseismic hypocenter, fracture area (A) =M/μδ where δ is displacement along the slip plane. Since δ is not directly measured, it is initially estimated using an empirical relation as a function of M and corrected using a scaling factor (k) where k=Vf/[(Vi)η]. The scaling factor is calculated by comparing Vf to (Vi)η following a hydraulic fracture stimulation of an individual stage where the sum of the seismic moments is greatest (compared to all stages monitored) and energy released is only associated with fluid injection (e.g. not tectonic activity).
Modeling Low Salinity Waterflooding: Ion Exchange, Geochemistry and Wettability Alteration
Authors: Dang Cuong. T. , Nghiem Long. X. , Chen Zhangxin , Nguyen Quoc. P. 
Published: September 2013

Abstract
Low salinity waterflood (LSW) has become an attractive enhanced oil recovery (EOR) method as it shows more advantages than conventional chemical EOR methods in terms of chemical costs, environmental impact, and field process implementation. Extensive laboratory studies in the past two decades have proposed several pore-scale mechanisms of oil displacement during LSW flooding, which are still open for discussion. However, the capability of reservoir simulators to model accurately this process is very limited. This paper provides a critical review of the state of the art in research and field applications of LSW. The focus is on a widely agreed mechanism that is the wettability alteration from preferential oil wetness to water wetness of formation rock surfaces. Ion exchange and geochemical reactions have been experimentally found to be important in oil mobilization due to enhanced water spreading at low salinity. To evaluate the significance of this surface wetting mechanism, a comprehensive ion exchange model with geochemical processes has been developed and coupled to the multi-phase multi-component flow equations in an equation-of-state compositional simulator. This new model captures most of the important physical and chemical phenomena that occur in LSW, including intra-aqueous reactions, mineral dissolution/precipitation, ion exchange and wettability alteration.
The proposed LSW model is tested using the low-salinity core-flood experiments reported by Fjelde et al. (2012) for a North Sea reservoir and the low-salinity and high-salinity heterogeneous core-flood experiments by Rivet (2009) for a Texas reservoir. Excellent agreements between the model and the experiments in terms of effluent ion concentrations, effluent pH, and oil recovery were achieved. In addition, the model was also proved to be highly comparable with the ion-exchange model of the geochemistry software PHREEQC for both low salinity and high salinity (Appelo, 1994). Important observations in laboratory and field tests such as local pH increase, decrease in divalent effluent concentration, mineralogy contributions, and the influence of connate water and injected brine compositions can be reproduced with the proposed LSW model. Built in a robust reservoir simulator, it serves as a powerful tool for LSW design and the interpretation of process performance in field tests.
Reducing Drilling Costs Through the Successful Implementation of a One-Run Monobore Well Strategy
Authors: Beaton Tim , Veloso Ryan , Kowbel Kevin , Specht Leo , Afseth Chris , Herman J. J. 
Published: September 2013

Abstract
As horizontal drilling programs continue to proliferate across the industry, and new technologies and operational practices are developed and advanced, the reality of a one-run well has emerged. In various applications across several provinces in Western Canada, the ultimate goal of drilling a horizontal well in one run from surface casing has been realized. This success comes as a function of the combined effort of the operator, directional drilling company and PDC bit company to solve the multitude of technical challenges facing a monobore strategy in areas with hole stability issues.
While many horizontal applications are now utilizing a monobore (one hole size) well plan below surface casing, the vast majority of those applications have one critical aspect in common - the upper hole sections are in very stable formations that can be left open for long periods of time. This is a critical aspect due to the fact that nearly all horizontal wells require multiple bits and multiple BHA configurations to reach total depth (TD). In areas where hole stability is an issue, an intermediate hole section is typically included in the well plan to seal off the unstable formations to allow the lateral interval of the well to be completed. In addition to the added time and costs required to set an intermediate string of casing, this type of well plan also results in a smaller hole size in the horizontal section.
In order to complete a horizontal monobore well through unstable formations, the well must be drilled in a very short period of time and must be drilled with excellent hole quality to eliminate any issues with rapidly completing the wells. This paper will detail a variety of these types of applications that successfully reached TD in 4-6 days from surface casing and were completed without problems.
This rapid monobore well approach leads to both huge cost savings for the well and a larger hole size in the reservoir for improved production. The result is more economical wells, drilled in much less time than conventional wells that yield greater returns.
Insights From History Matching and Forecasting Work for a Steeply-Dipping, Faulted Volatile Oil Reservoir
Authors: Kaul Sandeep P , Ambastha Anil , Eme Vincent , Creek Jefferson 
Published: September 2013

Abstract
History matching and subsequent forecasting work becomes a challenging task if limited supporting production data is available and the reservoir is severely depleted. For an offshore, volatile-oil reservoir, added to this challenge was an uncertainty in fluid PVT, where the data clearly suggested presence of condensate, but with black-oil properties. The permeability distribution from logs was counterintuitive to the production data from the wells. The reservoir had a structural relief in excess of 1000 ft., most likely having API gradient, but both the API and the GOR data indicated that there were possible errors in measurement. There was uncertainty associated with original oil-water contact also. The production data showed the reservoir to follow primarily a classical solution gas-drive response, but simple material balance analysis proved a weak aquifer effect as well.
The approach followed in simulation was the process of elimination. Pressure match was first achieved, but questions remained about its robustness around the main sealing fault. GOR was targeted next and several different condensates and one full compositional fluid model of a nearby reservoir were unsuccessfully tested. For matching the historical gas production, a new high condensate yield fluid PVT was used. The idea of another oil-water contact (OWC) was tested in the saddle of the reservoir to account for most likely early water breakthrough in a well there. The secondary gas cap formation and its effects were crucial in achieving satisfactory history match.
The confidence in the history match, as having captured the physics of the flow, led to forecasting scenarios which were not possible with a black-oil model. Most of the data was found not to be erroneous. What was needed was judicious data interpretation to achieve satisfactory history match. To produce these kinds of depleted, faulted reservoirs further, a strategy to better manage the evolution of secondary gas cap was of utmost importance.