bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Effect of Live Crude on Alkaline-Surfactant-Polymer Formulations; Implications for Final Formulation Design
Authors: Southwick Jeffrey G. , Svec Yi , Chilek Greg , Shahin Gordon T. 
Published: February 2011

Abstract
Phase behavior experiments have identified several surfactant systems that develop high solubilization ratios and low interfacial tension with a specific dead paraffinic crude oil at specific salinities.
The purpose of this work is to test these surfactant systems with reconstituted live crude. Emulsion screening tests were performed in sight cells where an equilibrium amount of solution gas is dissolved in the crude at reservoir pressure (1100 psi). The results indicate that the surfactant is relatively more soluble in the oil phase under these conditions. Thus a formulated chemical slug for field conditions should contain either less salinity or a more hydrophilic surfactant system than that used in formulations with dead crude. Phase behavior measurements estimate this offset to be approximately 0.25% less NaCl for the particular live crude in this study. The relevance of this offset is shown by comparing the results of dead crude core floods with a live crude core flood. A control experiment pressurizing oil with nitrogen at the same condition, 1100 psi did not show enhanced relative surfactant solubility in the oil phase.
Abrasive Jet Perforating and Fiber-Enhanced Proppant Plug Isolation Improve Efficiencies in Multistage Horizontal Completions
Authors: Itibrout Tarik , Blevins John , Yates Malcolm , Taboada Juan Pablo , Trummer Sascha 
Published: February 2011

Abstract
The process of abrasive jet perforating deployed on coiled tubing (CT), fracturing down the CT and casing annulus, and isolation with proppant plugs has proven beneficial in reducing completion costs and improving operational efficiencies in multistage stimulation applications. Unlike conventional plug and perforation techniques, this process can be done in a single trip, allowing the well to be put on production immediately after the treatment because no bridge plugs have to be drilled. However in horizontal well applications, achieving isolation with proppant plugs can be very challenging due to gravity effects, proppant plug integrity concerns, and ease of fracturing the formation. Adding degradable fibers to proppant plugs has proven successful in achieving good isolation between stages in horizontal wellbores. The fibers not only help create bridging at the perforations, but they also keep the proppant from settling to the bottom of the pipe thereby maintaining the integrity of the proppant plug. This approach has been used successfully in several abrasive jetting fracturing treatments in horizontal wells in West Texas and Southeast New Mexico. Well completion times have been reduced from over a week to only two to three days while allowing for more intervals to be selectively stimulated. Initial production results from the wells completed with the new technique have considerable improvement compared to previous stimulation methods.
Optimum Operating Conditions for Steady-State Two-Phase Flow in Pore Networks: Conceptual Justification Based on Statistical Thermodynamics
Authors: Valavanides Marios S. 
Published: February 2011

Abstract
The mechanistic model DeProF considers steady-state two-phase flow in porous media as a composition of three flow patterns: connected-oil pathway, ganglion dynamics and drop traffic flow. Their key difference is the degree of disconnection of the non-wetting phase which affects the relative magnitude of the rate of energy dissipation caused by capillary effects compared to that caused by viscous stresses. An appropriate mesoscopic scale analysis defines the process independent variables to be the capillary number, Ca, and the oil-water flowrate ratio, r, and leads to the determination of all the internal flow arrangements that are compatible with the externally imposed flow conditions. The observed macroscopic flow is an average over the canonical ensemble of the internal flow arrangements at mesoscopic scale. Extensive simulations using the DeProF algorithm revealed that there exist a continuous line, r*(Ca), in the domain of the process operational variables, (Ca, r) on which the efficiency of the process (oil produced per kW dissipated in pumps) attains a local maximum. The locus r*(Ca) defines the process optimum operating conditions. These findings are consistent with the phenomenology already presented in many experimental works.
The scope of the present work is to introduce a rational justification of the existence of the locally optimum operating conditions predicted by the DeProF theory.
Steady-state two-phase flow in porous media is a stationary process maintained in dynamic equilibrium on the expense of energy supplied to the system (an off-equilibrium process). The efficiency of the process depends on its spontaneity, measurable by the rate of global entropy production. The latter is the sum of two components: the rate of mechanical energy dissipation at constant temperature and a conformational entropy production component, directly related to the number of internal flow arrangements.
The DeProF algorithm simulations indicate that: for every oil-water-pore network system, optimum operating conditions exist for the r*(Ca) values for which the rate of global entropy production becomes maximum, i.e. when the process is as spontaneous as physically possible.
The conceptual statement introduced here is an initial approach towards implementing aspects of statistical thermodynamics to elucidate further the underlying physics of the process.
Improving Well Productivity through Openhole Frac-Pack Completion Design
Authors: Kamps Emil J. , Chando Jesse M. , Ellis Richard C. 
Published: February 2011

Abstract
Formation damage due to fines migration after the onset of water production presents a major technical challenge for many sandstone reservoirs around the globe. Oftentimes, significant productivity impairment is observed shortly after water breakthrough. This is particularly true for the Chad Doba basin lower "M" and "A" Sand reservoirs where studies have shown that a major contributor to this damage mechanism is the fluid velocity near the wellbore. As a result, exponential decline in productivity index is typically observed over very short periods.
To arrest the productivity impairment, various completion techniques were evaluated for ways to reduce the velocity of the produced fluids near the borehole. Typical completion designs employed to date have been cased hole gravel packs (including frac-packs) which enhances the velocity profile of the well as produced fluids converge to the perforations. Maximizing the reservoir to the wellbore interface reduces the velocity profile and conceptually prolongs the onset of formation damage caused by fines migration. Based on that conceptual model, openhole completion techniques were evaluated for feasibility. Upon analyzing the geology of the selected candidate, it became apparent that fracturing the formation was possible as it was a relatively thin amalgamated sand package. As a result, the openhole frac-pack concept became a practical option as it results in the lowest velocity completion possible by maximizing the reservoir surface flow area.
Openhole frac-pack completion activities were executed in mid-2009 and well productivity has been sustained even after water breakthrough. This paper reviews initial openhole frac-pack design concepts, execution lessons learned, and well productivity performance.
Making High Quality Frac Water out of Oilfield Waste
Authors: Hutchings Nathan R. , Appleton Eric W. , McGinnis Robert A. 
Published: February 2011

Abstract
Fresh water and affordable energy are two of the most valuable resources on the planet for sustaining economic growth and development. As the demand for oil and gas continues to increase, the fresh water consumption rate by exploration and production (E&P) activities is skyrocketing. Competition for fresh water is threatening to become an industry-limiting factor in some oil and gas plays. To ensure that the fresh water needed by the oil and gas industry is available in the future, better water resource management practices must be developed and implemented.
Currently, the drilling, completion, and stimulation of each horizontal shale well consumes up to 10 million gallons (gal) of fresh water, roughly equal to daily indoor water usage of 125,000 people [U.S. Department of the Interior March 2010]. Once fresh water becomes oilfield waste, the water is typically disposed of into reservoirs below the fresh water table, permanently removing it from the fresh water cycle. Reusing the water is desirable but often presents technical problems with water quality, water management logistics, and cost.
To help address these problems, a Forward Osmosis (FO) water reclamation process has been adapted for the oil and gas industry. The first generation of the process reclaims drilling waste water by converting it into high quality base fluid for hydraulic fracturing. In contrast to other water treatment systems, like reverse osmosis and evaporation, FO is a unique nano-filtration technology that harnesses the potential energy in a brine water solution as the drive mechanism, thus making the technology extremely "green" and cost competitive. Unlike conventional filtration to remove solids, the FO membrane rejects all solids and virtually all solutes from the reclaimed water, thus yielding a nano-pure water that will not react adversely with fracturing chemicals or the reservoir.
The results of laboratory and field testing from early commercial jobs show that FO is a viable technology for the reclamation of drilling waste for beneficial reuse as a high quality completion fluid. The results also show that FO can help significantly reduce both the carbon footprint and water footprint of the oil and gas industry.
An Analytical Model To Determine the Rheological Properties of Well Fluids Using a Novel Downhole Sensor
Authors: Rondon J. , Naughton Mac , Barrufet M. A. , Falcone G. 
Published: February 2011

Abstract
The ability to measure the true viscosity of formation fluids at downhole conditions is highly desirable in reservoir fluid characterization. A novel downhole viscosity sensor that can provide the real-time measurement of the viscosity of a flowing fluid at downhole conditions is discussed in this paper. The measurement can be obtained during open hole sampling of reservoir fluids, or during fluid profiling to characterize the reservoir properties at a vertical resolution much higher than that of traditional sampling methods. This leads to reservoir better understanding of the reservoir, leading to better decision-making with regards to field modeling, facilities planning and production optimization.
A prototype of a downhole sensor was previously calibrated and tested with fluids of 1-28 cP viscosity, under a temperature range of 100°to 160°F. The sensor's viscosity readings were validated against independent measurements taken with a Brookfield viscometer. Following on from that work, this paper presents a generalized mathematical model to describe the performance of the sensor with Newtonian and Non-Newtonian fluids. The model characterizes the response of the sensor as a function of the parameters from a power-law model rheological description and the geometry of the device. The previously gathered experimental data suggest the validity of this model for predicting the sensor response under realistic operating conditions. The model can be used to calculate optimum dimensions to fabricate a device for customized applications.
Successful Hydrofracturing Leads to Opening of New Frontiers in Shale Gas Production in the Cambay Basin in Gujarat, India
Authors: Sharma Shyam Sundar , Kulkarni P.K. , Kumar Anil , Pankaj Piyush , Ramanathan Venkateshwaran , Susanta Pande 
Published: February 2011

Abstract
Dholka, a small field situated in the Cambay basin of Gujarat consists of mainly oil producing horizons namely upper, lower, and middle pay. However, in a well D-A there is approximately 20 m interlaying shale above the upper pay showing a significant amount of C1 and C2 components evident from mud log showing yellow fluorescence. Around 24% of gas content was estimated, and hence, it was a considered as a potential source of gas pay that could be exploited using the hydraulic fracturing technique. This discovery occurred during the drilling and development phase for the lower, middle, and upper pay formations and is the first play in the field to have shale gas characteristics encountered. The change in cuttings and the show of gases in the chromatograph led to the careful collection of all the cuttings across these intervals, which were then sent for lithofacies and petrographic studies that confirmed that more than 50% of the facies are shale.
Apart from the upper pay and lower pay, an interesting shale pay zone was encountered in the well D-A during drilling. The hydrocarbon flow potential post perforating was very low because the formation was extremely tight. Hydraulic fracturing was critical for the successful producibility of such wells. To assess the maximum potential of both hydrocarbon bearing intervals, it was decided to hydro-fracture both shale and typical oil bearing intervals separately.
The planning and design processes of this project led to the successful execution of the hydraulic fracture. Encouraged by the results on the well D-A, another well D-B was similarly hydro-fractured as pilot test to explore shale gas in the area. Lessons learned from this successful experience have led Joshi Technologies to consider this source for further detailed exploration and development.
Case Study of Iraq: Education and Training Partnerships Among International Universities, IOCs, and NOCs
Authors: Van Kirk Craig W. , Baughman Gary L. 
Published: February 2011

Abstract
This paper presents a case study of the international partnerships among several universities in Iraq and the Colorado School of Mines (CSM) from the perspective of the CSM personnel involved over the past 35 years. Focus is on the several current and ongoing projects which occupy today's activities and which will continue to be active for some time to come.
These current innovative collaborations are partnerships which include CSM, one or more Iraqi universities, at least one International Oil Company (IOC), the Iraqi National Oil Company (NOC), South Oil Company (SOC), the Ministry of Oil, and the Ministry of Higher Education. The primary university programs which are engaged in these joint projects at this time are the petroleum engineering (PE) department at CSM and the PE departments at Baghdad University and other Iraqi PE-related universities. The primary project presented in this paper describes the current development of a new campus in Basra which focuses on serving the future needs of the oil and gas sector, which is known as the Basra Petroleum College (BPC).
The focus of these projects has always been, and continues to be, the oil and gas sector upstream Exploration and Production (E&P) disciplines of PE, geology (GE), and geophysics (GP); with appropriate attention being paid to and incorporating the other downstream and closely related groups of process engineering, petroleum economics, business management, and contracts and law.
Current and developing joint projects are described, along with an overview of the pertinent historical records which help explain how such partnerships develop and why some are more successful than others. The paper addresses knowledge transfer in PE education (and the several other disciplines identified above) at the undergraduate and graduate levels, university research, training industry and government professionals, and the essential roles of NOCs and IOCs in providing their guidance and financial support.
This paper is one of a series of connected papers and should be reviewed in conjunction with two other SPE papers by these same authors, as shown in the References.
Analysis of Nitrogen Stimulation Technique in Shallow CBM Formations
Authors: Settari A. (Tony) , Bachman R. C. , Bothwell P. 
Published: February 2011

Abstract
Nitrogen (N2) stimulation has become the preferred technique for stimulation of coal seams in the Horseshoe Canyon play in Alberta. It consists of stimulating each seam by pumping at very high rates for short time (2-4 mins). Because the coal is producible at shallow depths, ERCB has been developing and updating regulatory guidelines that aim to protect the freshwater supply.
This study was undertaken to improve the understanding of the process and provide recommendations on the regulatory guidelines for shallow depth (less than 200 m). The study was provided with extensive data from the industry (over 20,000 fractures in over 2000 wells) and has carried out several types of analyses in order to estimate fracture orientation and dimensions, and their dependence on N2 injection rate, duration and reservoir parameters. This included statistical analysis of large amounts of surface pressure data, pressure transient analysis of downhole pressure data, analysis of fracture mapping data, and conceptual simulations of the injection process using coupled reservoir and geomechanical models. Coupled geomechanical modeling provided realistic physical model of the process (in contrast to conventional models). Stress dependence of coal permeability and permeability anisotropy were shown to be the controlling mechanisms. This model was then used to investigate height growth mechanisms.
After considering the results of the analysis, its limitations, uncertainties in geological description of the coal and shale sequences, available case histories, and other factors, recommendations were made for modifications of the ERCB Shallow fracturing Directive 27.
Comprehensive Approach to Severe Lost Circulation Problems in Russia
Authors: Collins Natalia , Kharitonov Andrei , Whitfill Don , Miller Matthew 
Published: February 2011

Abstract
In the past, a favored approach may have been used to treat most or all lost circulation incidents. However, improvements in understanding all aspects of lost circulation show that the “favored approach” method can be technically unwise today. The delineation of fracture geometry induced during drilling, based on rock properties, may point out significant differences in the length and width and severity of anticipated induced fractures. Major differences in permeability between shale, sandstone and vugular limestone also show immediately that “one-size-fits-all” solutions are not going to be effective or efficient. When possible, these types of information need to be incorporated into any plan for controlling lost circulation.
Lost circulation is a principal culprit in drilling non-productive time (NPT). Generally speaking, the drilling industry handles lost circulation much as it did many years ago, but new modeling and operational techniques are changing industry perceptions. The petroleum industry has invested a significant effort into understanding the mechanisms behind lost circulation, developing new tools to help locate the thief zone, and implementing new steps to minimize or eliminate this problem.
Controlling loss of circulation during well construction is more than just selecting the proper type of lost circulation material (LCM). A fully engineered wellbore stress management (WSM) approach is required. During the planning phase, this approach incorporates borehole stability analysis, equivalent circulating density (ECD) modeling, leak-off flow-path geometry modeling, plus drilling fluid and LCM material selection to help minimize effects on ECD.
During the execution phase, real-time hydraulics modeling, pressure-while-drilling (PWD) data, connection flow monitoring techniques, and timely application of LCM and treatments are proving to minimize and in some cases eliminate losses in high-risk areas.
Multiphase Flow Splitting in Parallel/Looped Pipelines
Authors: Alvarez L. , Mohan R. S. , Shoham O. , Avila C. 
Published: February 2011

Abstract
A novel and unique experimental facility was design, constructed and instrumented, enabling slug flow splitting data acquisition in both parallel and looped lines. A total of 81 experimental test runs were carried out for various superficial gas and liquid velocity combinations. Uneven split conditions data were acquired by utilizing either a choke valve on one of the lines or different pipe diameters. For the symmetrical configurations of both parallel and looped equal diameter lines, the phases split equally in the lines. When the parallel and looped lines are of different resistance to flow (utilizing a choke installed on one of the lines or different line diameters), uneven split of the phases occurs. The gas-phase flows preferentially into the smaller resistance line. This results in different gas-liquid ratios in the two lines, which are different from the gas-liquid ratio at the inlet. A mechanistic model has been developed for the prediction of the uneven gas and liquid splitting and the pressure drop in two-phase looped lines. Good agreement is observed between the model predictions and the experimental data, with an average error of about 15% in the phase splitting and pressure drop.
Direct Method of Estimating Average Reservoir Pressure for Flowing Oil and Gas Wells
Authors: Agarwal Ram G. 
Published: February 2011

Abstract
A knowledge of the average reservoir pressure (p¯) and its changes as a function of time or cumulative production is essential to determine the oil-in-place (OIP) or original gas-in-place (OGIP), to estimate reserves and to track and optimize reservoir performance. The common practice of determining p¯ in moderate permeability reservoirs has been to run pressure buildup tests. In the current economic environment, buildup tests are almost non-existent except for very expensive exploratory wells. Moreover, time required for a pressure buildup test to reach p¯ in low permeability reservoirs is prohibitively long. Fortunately, flowing pressures and rate data are continually collected from oil and gas wells. Data quality and quantity is usually good especially from wells installed with permanent pressure gauges. Such data for gas wells is currently being analyzed by assuming OGIP and estimating p¯ required for calculating pseudo time. This is done in an iterative manner for using advanced decline curve analysis methods.
The purpose of this paper is to discuss a new finding that will enable direct estimation of p¯ using flowing pressures and rate data obtained from oil and gas wells during the pseudo steady-state flow period. In theory, pseudo steady-state flow requires that a well is produced at a constant rate. However, this limitation can be easily removed based on the work published in the SPE literature by this author and others whereby variable rate data can be converted to constant rate production data.
The significance of the subject paper is that it will permit: a) direct determination of p¯ using flowing wellbore pressures and rate data thus facilitating estimates of OGIP and OIP, b) estimation and/or validation of the value of the initial reservoir pressure (pi), which is normally suspect, and finally, c) enhancement or possible elimination of the current iterative process used for determining OGIP by advanced decline curve analysis methods.