bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Stable Fracturing Fluid for Produced Water Applications
Authors: Gupta D.V. Satya , Carman Paul , Venugopal Rupa 
Published: October 2012

Abstract
As shale fracturing operations continue to increase, so do the required volumes of relatively fresh water - which in some areas is limited in availability for fracturing. Exacerbating the issue, the water that is produced back after fracturing typically contains large amounts of total dissolved solids (TDS), including sodium, calcium, magnesium, barium and other salts. Storing and disposing of this water is becoming very expensive, and operators increasingly seek options for recycling and reusing this water. An ideal solution would be to reuse it in subsequent fracturing, but conventional fracturing fluid systems require fairly low TDS to achieve reliably stable rheology, so produced water typically requires extensive treatment before it can be reused for fracturing.
A new polymer system has been designed to viscosify produced waters a minimal filtration to eliminate large solid particulates. In addition to achieving stable viscosity despite the dissolved solids in the water, the system simplifies operations, requiring only a gellant, surfactant and breaker added on the fly to the water. No buffer, crosslinker or other additives are necessary. The unique polymer system uses a specialized surfactant to create an association with the produced water and generate viscosity. The resulting fluid is elastic and has excellent proppant transport characteristics. The system can be broken efficiently to achieve good regain conductivity. This paper will present the chemistry and results of complete laboratory testing to evaluate the fluid for fracturing operations. Testing will include demonstrations of fluid properties with typical produced water samples from the Bakken and Marcellus shales.
Explicit Calculation of Expansion Factors for Collision Avoidance between Two Co-planar Survey Error Ellipses
Authors: Sawaryn S. J. , Jamieson A. L. , McGregor A. E. 
Published: October 2012

Abstract
The positional uncertainty about a point on a wellbore is commonly represented as an ellipsoid. The ellipsoid also accounts for the dimensions of the casing or open hole. Using this model, at any time the resulting uncertainty about a wellbore along its trajectory is a curved, continuous cone. To a good approximation, the intersection of the plane normal to a reference well with these cones can be represented as ellipses. This simple geometrical model has been adopted by various standards organisations to define minimum acceptable separation distances between well bores, for example the Norwegian NORSOK D-10 standard.
Because of mathematical difficulties, the existing methods for calculating the resulting separation factors are only approximations and may be either too optimistic or too conservative, particularly for ellipses with high eccentricities. The paper presents explicit equations for determining the exact condition where the ellipses touch, expressing the result as an expansion scale factor. Methods are presented for the expansion of either one, or both ellipses, together with implementation notes and other associated tools. The new algorithms are only marginally less efficient than the existing approximation methods and they can be used to increase the allowable proximity of two adjacent wells whilst satisfying the geometrical and probabilistic constraints. The examples included in the paper illustrate this.
The proposed calculation method is consistent with existing industry wellbore uncertainty models. Since the determination of the osculating condition is exact, the calculation is neither too optimistic nor too conservative. This paper is a response to discussions held at the SPE Wellbore Positioning Technical Section meeting on 3rd November 2011.
High Reliability Gas Lift Flow Control Device Technology and Erosion/Endurance Tests
Authors: Xu Jun , Scott Stuart L. , Mabry Wayne , Gamboa Jose 
Published: October 2012

Abstract
High reliability gas-lift flow control devices (FCD) enable gas lift for wells with the potential for H2S in the produced gas and where casing is not qualified for H2S service. H2S is a potential for wells undergoing a waterflood, so the business impact of this technology is significant with the growing use of waterfloods in offshore fields. Specification of these valves is such that no leakage is allowed at both high (8000 psi) and low (1 psi) differential pressures across the valve. In addition, the extremely high intervention cost of subsea or TLP wells coupled with HSE challenge posed by sour fluid production in non-Shell qualified casing service require a higher level of gas-lift valve's reliability under this extreme environment. This paper describes the new technology of high reliability gas-flow control devises ensuring that the annulus volume is displaced only once. A series of testing programs were designed utilizing the ESS (environmental stress screen) concept and harsh test standard that greatly exceeds API specification for gas-lift FCD.
In 2009, Shell UA deepwater qualified three vender's gas-lift flow control devices using the Shell specified high reliability qualification standards. In 2010, Shell conducted valve cycling tests on the qualified valves at the Colorado Engineering Experiment Station. In 2011, Shell continued to work with Tulsa University to build up a new erosion testing facility and carry out a series of erosion/endurance tests on Shell qualified gas-lift flow control devices with Barite and water mixture. The purpose for Barite erosion tests was to determine if the Shell qualified gas-lift control devices can survive high density and high volume flow without the failure of the check system. This paper details the test procedures developed and some of the key findings of this qualification program.
Successful Application of Electric Line Tractor Assisted Logging and Perforating Technology Saved Significant Time and Associated Rig Costs, and Set Two New Regional Records in Latin America: A Case Study
Authors: Nunez-Garcia Walter , Arciniegas Jaime , Alvarez Ricardo , Valencia Brian , Villamizar Carlos , Goksal Mehmet , Parra Elba , Salom Ramon 
Published: October 2012

Abstract
A new well logging/perforating challenge arose from a High Slanted (HS) exploratory well that was drilled in Colombia. The HS exploration well (75 degrees inclination) was drilled in the "Llanos Area" to 18,040 ft MD. Available logging and perforating technologies were reviewed. Tubing Conveyed Perforating (TCP), using a combination of Drill Pipe (DP) / tubing string, and Coiled Tubing (CT) perforating technologies, was considered as part of the evaluation, but the selected method was an electric line well tractor to deploy the logging tool and perforating assembly. Using tractor conveyance saved significant time and associated rig costs over pipe conveyance to perforate a new well, and set two Latin American regional records for tractor-conveyed tools in one well.
Based on site-specific experience, the operator concluded that each well intervention with drill pipe would require 48 hours per trip. In August 2011, after a formal risk analysis and systems integration testing (SIT), the operator mobilized a down-hole robotics-solutions provider and successfully tractored a cement evaluation log to 11,079 ft. A regional record was set for longest tractor-conveyance during the first perforating run of 12,095 ft. A second perforating run of 11,037 ft was successful and set a regional record for longest cumulative tractor-conveyed distance in a single well at 34,211 ft. The cement evaluation and perforating runs were completed in less than 40 hours versus more than 96 hours, which was the estimate with pipe conveyance. The results of operations in the HS Llanos well are presented. Lessons learnt from these operations are part of this study.
Benchmarking, Asset Potential and Digital Energy
Authors: Reid Laurence , Szatny Michael , Johnson William D. , Lochmann Mark 
Published: October 2012

Abstract
Because digital-energy (DE) projects are intended to improve performance, both a normalized baseline describing existing conditions and targets (generally set by management) for future improvement are necessary. Today, only a few assets capture enough data to fully understand the status of operational activities or to quantify optimum reservoir behavior. A benchmark, or baseline, provides a way for companies to identify "where they are" and helps justify DE investments by tracking improvement. To optimize returns, asset potential should be established before appropriate targets are set. DE business impact (the difference between baseline and potential) may then be adequately evaluated.
Deviation from ideal performance may be a result of equipment limitations, facility availability and uptime, administrative or operational bottlenecks, fluid behavior, weather, employee skill set, and numerous other factors. Differences between assets may be attributed to artificial-lift cost variations, local economic conditions, onshore/offshore, lifecycle stage, asset type (shale, waterflood, deep water, coalbed methane, etc.), produced fluid, and many others.
Refining faces equally diverse problems and has taken the necessary steps to address this challenge by applying benchmarking with commercial tools, such as the Solomon Associates Indices, for ranking and comparing different refineries. For E&P, an initial external benchmarking framework based on public data (annual reports, EIA, 10Ks, IHS, etc.) will be discussed so that high-level performance metrics can be evaluated.
By developing a similar approach using proprietary and internal data, companies can begin to understand asset performance in detail and rank assets not only within an organization but also across company boundaries based on operational efficiency and effectiveness. Prioritizing DE projects based on their contribution also becomes possible. As DE projects are deployed, the benchmarks can be refined and updated for greater accuracy.
If the framework is properly designed, a company can see where gains are possible and adapt future programs to concentrate on areas where the most value can be derived, regardless of asset type, which will permit a company to forecast benefits and predict how effective a DE initiative could be.
Downhole Fluid Analysis and Asphaltene Nanoscience Coupled with VIT for Risk Reduction in Black Oil Production
Authors: Mishra Vinay K. , Skinner Carla , MacDonald Dennis , Hammou Nasr-eddine , Lehne Eric , Wu Jiehui , Zuo Julian Y. , Dong Chengli , Mullins Oliver C. 
Published: October 2012

Abstract
It has long been recognized that condensates can exhibit large compositional gradients. It is increasingly recognized that black oil columns can also exhibit substantial gradients. Moreover, significant advances in asphaltene science have provided the framework for modeling these gradients. For effective field development planning, it is important to understand possible variations in the oil column. These developments in petroleum science are being coupled with the new technology of downhole fluid analysis (DFA) to mitigate risk in oil production.
In this case study, DFA measurements revealed a large (10×) gradient of asphaltenes in a 100-m black oil column, with a corresponding large viscosity gradient. This asphaltene gradient was traced to the colloidal description of the asphaltenes, which yielded two conclusions: the asphaltenes are vertically equilibrated, consequently vertical connectivity is indicated, and the asphaltenes are partially destabilized. Vertical interference testing (VIT) was performed at several depths and confirmed the vertical connectivity of the oil column, with four of the five tests showing unambiguous vertical connectivity consistent with the overall connectivity implied by DFA. Geochemical analysis indicates that the instability was due to some late gas and condensate entry into the reservoir. For mitigation of production risk, flow assurance studies were performed and showed that while the asphaltenes are indeed partially destabilized, there is no significant associated problem. Moreover, thin sections of core were analyzed to detect possible bitumen. A very small quantity of bitumen was found, again confirming the asphaltene analysis; however, geochemical studies and flow assurance studies confirmed that this small amount of bitumen is not expected to create any reservoir issues.
Using new science and new technology to identify and minimize risk in oil production in combination with pressure transients addressed reservoir connectivity and provided a robust, positive assessment.
New Wireline Formation Tester Development Makes Sampling and Pressure Testing Possible in Extra-Heavy Oils in Mexico
Authors: Flores de Dios Tania , Aguilar Maria Guadalupe , Herrera Rafael Perez , Garcia German , Peyret Emilie , Ramirez Edher , Arias Abraham , Corre Pierre-Yves , Slapal Miroslav , Ayan Cosan 
Published: October 2012

Abstract
Accurate fluid description in the Tertiary sediments of Mexico is important for PEMEX operating assets because large variations in viscosity over very short intervals have a major impact on well productivity. Well placement and selection of the completion strategy in this kind of reservoirs strongly depend on the characterization of the fluid distribution. This is because the efficiency of steam injection and the artificial lift system can be severely impaired if a preferential path, following high mobility section (k/μ) exists over the producing intervals. Such is the case for the Samaria-Neogeno project, which has fluids with viscosity values up to 40,000 centipoise (cP) at standard conditions.
Wireline openhole formation testing and sampling in this environment is not short of challenges and hence is rarely done in the field. The poorly consolidated formations and the high viscosity of the fluids mean that the pressure differential generated during sampling operations almost invariably causes failure of the wellbore wall, sanding out the tool or breaking the seal needed. Other experiences in the world with straddle packers in similar formations have been mostly unsuccessful because the formation collapses in the unsupported interval between the packers once the pressure differential is applied.
This paper summarizes the recent successful application of the newest wireline formation tester (WFT) module for testing and sampling extra-heavy oils in the Tertiary sandstone formations of South Mexico. This is the world's first application of such technology in unconsolidated sandstones. The new WFT module provides mechanical support to the formation while allowing the application of the needed pressure differentials to mobilize formation fluid into the tool's flowline and sample containers. The case presented shows how ~8° API fluid samples with viscosities in the order of few thousands centipoises at downhole conditions were acquired using this new device. Other applications reviewed are pressure profiling and pressure transient tests for permeability evaluation.
Lessons Learned from an ESP Development of a Naturally Fractured Carbonate Reservoir Offshore Gabon
Authors: Camilleri L. , Hamza L. , Yucel O. , Rodet V. , Breton B. 
Published: October 2012

Abstract
The Ompoyi and Orindi fields are located 5 km offshore Gabon in a water depth of 20 m. The high oil density (23° API) and high produced water salinity (150 kppm) combined with reservoir pressure depletion meant that primary production of the Ozouri reservoir required artificial lift. Initially, progressing cavity pumps (PCPs) were selected, however, following failures of the elastomers, electric submersible pumps (ESPs) were deployed to produce at higher rates with high gas/oil ratios (GORs). The production instability associated with the dual-porosity reservoir behaviour and high free-gas content in both the inflow and outflow of the wells presented the main challenge to ESP design and operation. Additionally, most of the wells were remote from the main production facility and were produced via multiphase subsea flowlines, which made well testing difficult due to the phase segregation in the flowlines.
To achieve economically viable production utilizing ESPs, innovative use was made of a range of existing technology. Operationally, however, real-time monitoring was essential to setting wellhead pressures and pump speed to maximize drawdowns. Key technology elements were monopods to minimize the offshore structure cost, fit-for-purpose subsea power cable and helicoaxial downhole pumps for high gas void fraction operation. Key lessons were learned following the trial of several completion architectures to find the optimal combination of gas venting, reservoir access, and a dual barrier mechanism.
The first well was put on production in 2002. Since then a further 10 wells have been drilled to reach a total liquid production of 8,000 B/D with a 60% water cut. Production has been economical and thus confirmed ESPs as being the right solution for this reservoir. The lessons learned prove that the application of ESPs is not limited to traditional waterfloods and that it is feasible to produce challenging reservoirs with ESPs.
A Decade Monitoring Shale Gas Plays Using Microseismicity: Advances in the Understanding of Hydraulic Fracturing
Authors: Wuestefeld Andreas , Urbancic Thedor I. , Baig Adam , Prince Marc 
Published: October 2012

Abstract
Over the past decade, microsesimic monitoring has become the approach most often used to gain an in-situ understanding of the rock's response during hydraulic fracture stimulations. From initial monitoring performed in the Barnett Shale to monitoring currently being carried out for example in the Horn River and Marcellus formations, we review the evolution of microseismic monitoring from data collection (single versus multi-well array configurations, utilization of long lateral stimulation wells), to data analysis and the incorporation of microseismic parameters to constrain and validate reservoir models. Furthermore, we discuss the variations in microseismic activity for different stimulation programs (e.g. zipper-fracs) and stimulation fluids.
Generally, we have observed that overall fracture height, width and length, orientation, and growth vary from formation to formation and within each formation, thereby highlighting the ongoing necessity for microseismic monitoring. Additionally, through the use of advanced microseismic analysis techniques, such as Seismic Moment Tensor Inversion (SMTI), details on failure mechanisms have been used to assess stimulation effectiveness and define complex Discrete Fracture Networks (DFN). This information provides estimates of Enhanced Fluid Flow (EFF), which assist in calibrating and validating reservoir models. Utilizing spatial and temporal distributions in DFN and EFF, along with estimates of fracture interconnectivity and complexity, the role of pre-existing fractures and fault structures in the rock matrix can be established and used to provide more realistic estimates of stimulation parameters such as Stimulated Reservoir Volume (SRV).
Criticality Testing of Drilling Fluid Solids Control Equipment
Authors: Aase Bodil , Omland Tor Henry , Jensen Ellen Katrine , Vestbakke Anne Turid , Knudsen Bjarte Sivert , Haldorsen Frode , Nysted Arvid , Storslett Eystein Ove , Steinnes Iren , Eliassen Einar Knut , Enger Jørund , Lie Øyvind , Peikli Vegard 
Published: October 2012

Abstract
Correct selection and use of solids control equipment is essential to maintain drilling fluid at its desired properties. It has also shown to be essential to avoid generation of unnecessary waste streams during drilling.
Since the early 1930s shale shakers has been the dominant device for primary solids removal. Additional equipment like desilters, desanders and centrifuges were often used in the past to maintain proper solids control, but recent years have demonstrated that although dependent on correct operational procedures, several types of shale shakers have sufficient performance to be able to act as the sole solids control device without the use of desanders and desilters.
Despite often being the only measure for solids removal, selection of shale shakers, screen and establishment of operational procedures are often based on biased information (Dahl, B. et al, 2006). In addition it has been recognized that methods and criteria for verification of shale shakers has not been sufficiently qualified and standardized. To address this, a multidisciplinary verification test of various solids control concepts has been conducted. The objective of the test has been to verify equipment performance in a standardized onshore test facility related to:
Oil mist and vapour emission. Ventilation (to obtain satisfactory working environment). Flow handling capacity using various drilling fluids. Leakage rate, i.e. the volume of fluid bypassing the filtration screen Lost circulation material feature Noise and vibration level. Maintenance and equipment robustness. Feature for running lost circulation material reclamation.
The tests were all planned and run in close co-operation with the equipment suppliers to ensure test objective alignment. Several findings were made throughout the test period providing vital information for design improvements and increasing the industry's competence with respect to solids control.
Impact of Completion Design on Fracture Complexity in Horizontal Wells
Authors: Manchanda Ripudaman , Sharma Mukul M. 
Published: October 2012

Abstract
A proppant-filled fracture induces mechanical stresses in the surrounding rock causing a reduction in the stress contrast and stress re-orientation around the open fracture. A three-dimensional geo-mechanical model is used to simulate the stress reorientation due to open fractures and generate the stress contrast contour maps. The reduction in stress contrast can lead to increased fracture complexity. This paper describes how fracture complexity can be increased by varying the completion design.
In this paper, we identify the impact of operator-controllable variables in a completion design on fracture complexity. This can lead to more effective completion designs that improve well productivity, reservoir drainage and ultimately EUR.
The possibility of greater fracture complexity and reduced effective fracture spacing and hence higher drainage area is demonstrated for an alternate fracturing sequence in comparison to the conventional fracturing sequence. The Young's modulus value of the shale and the in-situ horizontal stress contrast are shown to be significant factors controlling the extent of fracture complexity generated in a given reservoir. In addition, the effect of proppant mass injected per stage and the fluid rheology is also shown to significantly impact fracture complexity. We provide optimum ranges of fracture spacing, proppant volume and fluid rheologythe various formations analyzed. The use of these guidelines should result in more fracture complexity than would otherwise be observed.
The results presented in the paper allow an operator to design completions and fracture treatments (rates, fluids, fracture spacing and sequencing) to maximize reservoir drainage and increase EURs. This will lead to more effective completion designs.