bluuebunny/crossref_metadata_2025_split huggingface dataset:
Wellbore Cleanup Tools Save Rig Time in Approximately 30% Optimizing Workover and Completion Operations
Authors: Cárdenas Jorge Luis , Rueda Ana , Guerra Edmundo , Vera Juan 
Published: October 2011

Abstract
During workover and well completion operations several sub-events are performed to put a well back on production or to start production on a new well. These events are carefully planned considering people, environment, reservoir, wellbore integrity, well productivity and final cost of workover and Completion.
In the oil business optimizing production costs is the way to go when a project is conducted with financial based criteria, but thinking about maximizing well productivity and avoiding deferred production is also important when a project is being planned.
Conventional wellbore cleanup practices are often used in the industry but sometimes this process is not considered as an important part of the operations. Common problems associated to oil production that may reduce the well productivity like inorganic scale, sand, corrosion, paraffin and asphaltenes can be removed with specific wellbore cleanup tools and techniques. The time associated to clean up a well represents 40% up to 60% of the total workover time using conventional cleaning tools.
Continuous process improvement and risk management has helped to use an alternative method that improved cleaning process reducing time and all the associated costs, this method includes the use of new technology on non rotating tools (scrappers and brushes), magnets, filters and sand recovery tools.
Additional benefits are also obtained using this new technology, such as minimizing non-productive time, reduction of formation damage due to workover fluids and rock interaction, improvement of ESPs run life among others.
This paper describes how changing the wellbore cleanup methods and the use of appropriate tools had permitted to reduce rig time in about 30% when a well is being intervened. The study includes information of one year using wellbore cleanup tools in more than 70 wells in Tarapoa onshore Field located in Ecuador. Significant cost reduction and anticipated oil production demonstrate that this method can be economically applied.
Shale Oil Production Performance from a Stimulated Reservoir Volume
Authors: Chaudhary Anish Singh , Ehlig-Economides Christine , Wattenbarger Robert 
Published: October 2011

Abstract
The horizontal well with multiple transverse fractures has proven to be an effective strategy for shale gas reservoir exploitation. Some operators are successfully producing shale oil using the same strategy. Due to its higher viscosity and eventual 2-phase flow conditions when the formation pressure drops below the oil bubble point pressure, shale oil is limited to lower recovery efficiency than shale gas. However, the recently discovered Eagle Ford formations is significantly overpressured, and initial formation pressures is well above the bubble point pressure in the oil window. This, coupled with successful hydraulic fracturing methodologies, is leading to commercial wells. This study evaluates the recovery potential for oil produced both above and below the bubble point pressure from very low permeability unconventional oil formations.
Relative permeability behavior, including the critical gas saturation, is likely to be quite different in created fractures from that of the shale matrix, and technology for laboratory multiphase flow measurements has not been developed for such low absolute permeability values as are found in shale formations. Further, propent embedment and expected multi-phase flow in the created hydraulic fractures can lead to actual values of fracture conductivity in the created fractures order of magnitude lower than the values reported in the laboratory.
As with shale gas, high recovery in shale oil wells will require that created hydraulic fractures are spaced close enough to result in interfracture interference during the time the well is on production. This study investigates the role of the fracture spacing, fracture conductivity, fracture half-length, critical gas saturation, flowing bottom-hole pressure and matrix permeability in the well economics and the ultimate recovery efficiency considering flow both above and below the bubble point pressure and using known properties of successful shale oil plays. Simulations show that results are strongly dependent on assumed relative permeability behavior, and sensitivity studies provide considerable insight about the long term production behavior than can be expected in these wells.
A New Coiled Tubing Application to Enhance Operating Envelope for Deepwater Production
Authors: Dong Hongkun , Shi Hua , Norris Lee , Berger Ron 
Published: October 2011

Abstract
The objectives of this study were to investigate the effects of coiled tubing size, flow path, gas lift and water cut on the onset of severe slugging and overall operating envelope. The coiled tubing was investigated as a technique for delaying the onset of slugging, which involved the use of larger diameter coiled tubing strings to decrease the flowing area in the annulus, or routing the flow up within coiled tubing instead of annulus to flow directly in coiled tubing. The operating envelope considering slugging and other system constraints was also investigated with the use of coiled tubing. The minimum nonslugging rate was reduced by using larger coiled tubing size with normal flow through annulus. A very low non-slugging rate was achieved with small diameter coiled tubing when producing through the coiled tubing, but a very narrow operation window was left when other system constraints were considered. The minimum non-slugging rate increased rapidly as the coiled tubing size increased when flowing within coiled tubing. Gas lift was effective in reducing the minimum non-slugging rate when it was increased from 0 to 4 mmscfd, but not very effective in one of the risers when it was further increased from 4 to 8 mmscfd. Increase of water cut appeared not to have a significant effect on the minimum non slugging rate.
The study explored a new way of coiled tubing application in production design. It provides a guidance of how to effectively use coiled tubing as a technique to reduce the minimum non slugging rate, especially the flow through either annular or within coiled tubing. The field life can be extensively extended with a proper selection coiled tubing size, flow path and gas lift. A workflow of coiled tubing size selection and operating window determination considering different system constraints was also demonstrated.
Water As Proppant
Authors: Ehlig-Economides Christine A. , Economides Michael J. 
Published: October 2011

Abstract
The horizontal well with multiple transverse fractures, has proven to be a successful approach for production of gas from shale. As many as 80 fractures and nearly 10 million gallons of fracture fluid have been employed in a single well. However, unlike for conventional hydraulic fractures, in shale gas wells most of the treatment water never flows back.
In this paper we postulate that the water has actually stayed in the created fractures and/or in enhanced natural fractures. The reason why fractures exhibit high conductivity flow behavior even with very little proppant is because the water injected in the fractures cannot leak off into the shale matrix, and relative permeability in the fracture impairs the water from flowing back. Water remaining in the fractures actually prevents them from closing. Gas bubbles or channels to the horizontal borehole through water in the fractures.
In shale gas formations some diagnostic fluid injection tests appear to never exhibit closure or close with indicated fluid efficiency of 90% or more. In the period during execution and before flow back, water is too viscous for the large fluid volumes injected to flow into the extremely low permeability shale matrix. If treatment water could leak off, unpropped fractures in shale would likely close. Because the gas is water-saturated as it enters the water filled fracture, there is little tendency to vaporize the water. Therefore, water as proppant resolves both the question why so much treatment water never flows back and why fracture complexity can remain open indefinitely without proppant slurry.
Characterization of Well Performance in Unconventional Reservoirs using Production Data Diagnostics
Authors: Ilk D. , Okouma V. , Blasingame T. A. 
Published: October 2011

Abstract
Production analysis and forecast in unconventional reservoirs are challenging tasks due to high degree of uncertainty and non-uniqueness associated with well/reservoir properties. At this point the importance of diagnosis of production data to check the data consistency and to identify flow regimes has become significant. In addition, we believe that producing wells in various unconventional reservoirs exhibit unique production performance behavior due to geology, phase behavior, and completion practices. Therefore, the identification of the related performance behavior is crucial for development and forecast purposes.
The primary objective of this work is to apply diagnostic methods to investigate and understand production performance characteristics of the wells producing in unconventional reservoir systems. For our purposes, we present examples from various shale gas plays.
We propose the use of various forms of rate-time and rate-time-pressure plots for production data diagnostics. In particular, this work presents the utilization of the dimensionless βq,cp-derivative formulation (i.e., logarithmic derivative of the rate function with respect to logarithm of time) to identify production behavior characteristics. We also propose the use of several diagnostic plots to identify performance characteristics and data consistency. In addition the use of average rate functions are presented for better resolution.
Accurate Measurement, Correlation and Simulation of Multi-component BTEX Solubility in Amine Solutions
Authors: Borda R. T. , Civan F. 
Published: October 2011

Abstract
The accurate prediction of BTEX solubility in natural gas conditioning processes is of major importance since the monitoring of the emissions of these contaminants to the atmosphere depends on this knowledge. This paper presents experimental solubility data of a multi-component gas composed by Methane, Benzene, Toluene, Ethylbenzene and p-Xylene into MDEA solutions. The gas-liquid system used in this work represents a realistic experimental environment. The synthetic multicomponent gas used in the experiments has similar BTEX content than that of a real gas processing plant. A material balance method is used to obtain accurate solubility results. Gas chromatography (GC) analysis is performed to determine the solubility of the BTEX compounds of the multi-component gas. Experimental data is analyzed, correlated and compared to literature and commercial software results. The results from all the sources is discussed and compared side by side.
Multidisciplinary Team Implementation: A Step Beyond Integration
Authors: Battalora L. A. , Curtis J. B. , Davis T. L. , Miller M. G. , Smith B. W. , Sonnenberg S. A 
Published: October 2011

Abstract
An educational model exists at the Colorado School of Mines (CSM) that responds to current industry objectives, incorporates the SPE Professional Competency Matrices1 (hereinafter, Competency Matrices) and satisfies the Accreditation Board of Engineering and Technology (ABET)2 requirements. GEGN/GPGN/PEGN439 Multidisciplinary Petroleum Design (hereinafter, 439 Capstone Course) is the cross-discipline, senior-level, capstone design course in the Geological Engineering, Geophysical Engineering and Petroleum Engineering Departments. Historically, the 439 Capstone Course has met ABET requirements and industry objectives by providing students with multidisciplinary problem solving and integrated team experience prior to entering the work force. Teamwork experiences focused on the integration of data, information, and people from the disciplines of geology, geophysics, and petroleum engineering. However, the need exists to move beyond "integration" with a step forward to "implementation." Using the Competency Matrices as a guideline and responding to industry feedback, the revised 439 Capstone Course is a novel educational approach that accomplishes this goal.
Well Evolution in the James Lime: How Technology has Driven Well Productivity Improvements
Authors: Baihly Jason , Altman Raphael , Aviles Isaac , Seale Rocky , Snyder D J 
Published: October 2011

ABSTRACT
The James Lime is a carbonate formation located along the United States Gulf of Mexico upper coast. Exploration wells were drilled in the James Lime beginning in the 1950's, with commercial activity occurring in the following decade. Wells were drilled exclusively vertical from its discovery through the late 1990's. Over this timeframe, these wells had a great deal of variability in production which hindered the development of the play. Given the apparent rock potential, the production results from these types of completions were oftentimes disappointing and uneconomical.
Many different types of drilling and completion technologies have been attempted over the history of the James Lime in order to improve production results. Little has been publicly documented on the impact of these step changes attempted on the James Lime. One striking technological innovation occurred in the late 1990's when operators started drilling wells horizontally in the James Lime. Initially these wells were either not stimulated or completed with a single stage hydraulic fracturing treatment. Just drilling horizontally had little impact on production results and consistency. Within a few years of horizontal development, wells started to be hydraulically fractured with multiple treatment stages using advanced open-hole multistage isolation systems. These two technological innovations along with others had an impact on increasing James Lime production over time. (IHS, 2011)
This paper analyzes the various drilling and completion technologies that have been applied to the James Lime over its 50 year history. The impact on production of these practices since 1995 is also presented. Some of the variants analyzed to determine their impact on production include hole direction, lateral length, completion isolation system, and number of stages treated. Hydraulic fracturing treatment details such as proppant type, treatment volume, and proppant volume were analyzed to determine their impact on production results as well. Other factors were taken into consideration when performing the production analysis including the timeframe when the well was drilled and completed.
The results of this analysis uncovered the impact on production that technological advancements had over time on the tight James Lime carbonate formation. It highlights the key production drivers in the James Lime and how to improve production of future wells drilled in the formation. Furthermore, the lessons learned and key technologies from this formation can be applied to other tight carbonate plays around the world.
Optimal Fracture Spacing and Stimulation Design for Horizontal Wells in Unconventional Gas Reservoirs
Authors: Bhattacharya Srimoyee , Nikolaou Michael 
Published: October 2011

Abstract
Hydraulic fracturing of horizontal wells is crucial for economic production of natural gas from unconventional reservoirs. For transverse fractures, existing approaches for making decisions on fracture spacing and length are based on sensitivity analysis using reservoir and/or fracture propagation simulators. The use of commercial simulators relies on assessment of various what-if scenarios, which are set up based on experience and data collected from completed wells in the same or similar reservoirs. Because of the large number of possible decision variables, the decision-making process is complex, potentially leading to non-optimal. A computer-aided tool that could facilitate the process would allow engineers to efficiently converge to solutions that are at or close to the optimum.
The proposed approach relies on a novel efficient numerical optimization tool. The optimization objective function is Net Present Value (NPV) for horizontal wells drilled in the direction of the minimum horizontal stress, which allows multiple transverse fractures. Key decision variables are number of transverse fractures in a horizontal well; horizontal well length; proppant concentration; injection rate of fracturing fluid; injection time; fluid performance index and fluid consistency index. Key design constraints are fracture growth control, and geometric constraints. To set up the optimization, critical reservoir properties are assumed to be available from a variety of sources (e.g., seismic, prior production logs). The modified PKN model along with Carter's Equation for material balance is used for hydraulic fracturing propagation where fracture width, half length and net pressure are calculated. Productivity of multiple fractured horizontal wells is computed by using analytical equations. A robust optimization algorithm is used for finding the optimum parameters.
The capability and robustness of the proposed approach is demonstrated for a tight gas reservoir for which horizontal well geometry and its fracturing treatment is designed based on numerical simulations. A commercial simulator served as virtual reservoir with properties calibrated based on SPE case studies. The simulation show optimization can significantly increase NPV over other available solutions. Sensitivity analysis is done on various decision variables to show their significance in decision making for well stimulation. Also, significance of choosing optimum number of operating years is discussed in order to avoid missing optimum recovery. It is shown how important it is to find the optimum number of years for a particular formation which can give the maximum profit.
The proposed tool can provide a quantitative assessment of optimal horizontal well stimulations. It is envisioned to be used in an integrated decision support system that will help engineers to use a multitude of available data for development of unconventional gas resources.
Estimated Ultimate Recovery (EUR) as a Function of Production Practices in the Haynesville Shale
Authors: Okouma V. , Guillot F. , Sarfare M. , Sen V. , Ilk D. , Blasingame T. A. 
Published: October 2011

Abstract
Recent developments in well completion technologies have transformed the unconventional reservoir systems into economically feasible reservoirs. However, the uncertainty associated with production forecasts and non-uniqueness related with well/reservoir parameter estimation, are the main issues in future development of these reservoirs. In addition, recent operational methods such as restricting rates by decreasing the choke size add up to the uncertainty in production forecasts.
This work attempts to investigate the effect of production practices on ultimate recovery. It is observed that wells producing in the Haynesville shale gas play exhibit severe productivity loss throughout their producing life. Production practices such as controlling the drawdown or restricting rates by decreasing the choke size are employed by several operators to deal with the severe productivity loss. In this work our main objective is to investigate the issues (such as stress dependent permeability, proppant embedment, operational problems, etc.) contributing to decreasing well productivity over time. In particular, from modeling standpoint, we focus on stress-dependent permeability as a mechanism, which affects well performance over time.
Using a horizontal well with multiple fractures numerical simulation model coupled with geomechanics, we generate synthetic simulation cases including several drawdown scenarios. It is shown that high drawdown cases result in higher effective stress fields around the well and fracture system. We therefore infer that higher effective stress fields result in lower well productivity over time. Based on this hypothesis and diagnostics of field data, we model two different scenarios (i.e., high drawdown and low drawdown cases) for a horizontal well with multiple fractures using two different permeability decay functions and same well/formation model parameters. Our modelling results indicate that low drawdown case yields higher recovery suggesting that rate restriction could be a mitigating factor in decreasing well productivity over time.
Experimental and Field Data Analyses of Ball Sealer Diversion
Authors: Nozaki M. , Zhu D. , Hill A. D. 
Published: October 2011

Abstract
Diversion methods are routinely used in both matrix acidizing and fracturing stimulation treatments. The diversion methods are categorized into chemical diversion and mechanical diversion. In this study, we focus on one of the classical mechanical diversion methods, ball sealers. Ball sealer diversion is used in cased and perforated wells to divert stimulation fluids by temporarily blocking perforation holes in the casing with rubber-coated balls. This diversion method can be very effective, particularly with high rate injection, but no general methodology is available to design ball sealer diversion, or to evaluate its effectiveness from the treating rate and pressure record.
Although some design methodologies, such as the use of buoyant ball sealers to improve the ball sealer efficiency, have been suggested, no model has been presented for determining how many balls seat on the perforations. In this paper, experimental data from an extensive series of full-scale flow experiments conducted by BP were analyzed. We summarized several features of the ball sealer which are not presented in the literature. Also we used the procedure presented by Brown et al. (1963) to evaluate statistical nature of the ball behavior in the BP's experimental results. The BP experiments were designed to minimize scatter of data. However, the seating process was found to be statistical.
Also we analyzed one field acid fracturing treatment where ball sealers were used as a diversion method. Then the analyzed data were compared to the BP experimental results. A similar trend in seating efficiency was observed.
Toward Quantitative Remaining Oil Saturation (ROS): Determination Challenges and Techniques
Authors: Al-Harbi Ahmed , Schmitt Denis P. , Ma Shouxiang M. 
Published: October 2011

Abstract
Remaining Oil Saturation (ROS) is a crucial input to reservoir development projects. Determination of such a time-dependent parameter assists the evaluation of the sweep efficiency, provides calibration points for simulation models and also sets the basis for future workover and EOR projects.
Quantification of ROS in waterflooded areas has always been a known challenge to resistivity-based techniques. The mixed water salinity environment, due to differences between original connate water and injected water, and the impact of the imbibition process on the saturation exponents are the main hindrances.
Over the past few years, data acquisition strategies have been deployed to overcome these challenges. The strategies include in-situ measurements that are insensitive to water salinity and to fluid displacement processes, such as Nuclear Magnetic Resonance in Log-Inject-Log mode, Carbon/Oxygen, and Dielectric logs. Extensive wireline formation testing programs usually follow to confirm the findings from the aforementioned measurements. Depending on the well's criticality, special coring programs might also be included such as sponge coring or liquid trapper. Special planning and standardization efforts are necessary for such extensive data acquisition programs to ensure data quality and consistency.
This paper presents Saudi Aramco data acquisition strategies for ROS applications. It also highlights the main challenges and the technologies deployed to resolve them. Advantages and limitations of these technologies are reviewed. Lastly, our ongoing efforts to reduce the uncertainties of such analyses are presented.