bluuebunny/crossref_metadata_2025_split huggingface dataset:
New York Field Trial of Ultra-High Salinity Brine Pre-treatment: Texas A&M Environmentally Friendly Drilling Technology for the Marcellus Shale
Authors: Burnett D. B. , Vavra C. A. , Platt F. M. , McLeroy L. K. , Woods R. W. 
Published: October 2012

Abstract
Shale gas development relies heavily on multi-stage hydraulic fracturing to maximize the economic viability of each new well. In recent years, the industry is aiming at re-use of frac flow back brine to reduce costs and environmental impact of operations. The challenge is to identify technologies and approaches for treating the frac water that returns to the surface following a frac job (frac flowback water) for beneficial re-use in other applications, thereby conserving other local freshwater supplies. Field trials in upstate New York have been conducted to test new technology to treat brines characteristic of flow back brines from the Marcellus Shale and make them amenable for re-use in subsequent oil field operations.
The Texas A&M GPRI produced water treatment program began in the year 2000. In the past decade we have shown that produced water and frac flowback brine from shale gas and tight gas well drilling operations can be treated and reused instead of tapping in to additional fresh water resources. Now the program is working to demonstrate that low cost, mobile units can be deployed in field operations to replace the more costly and environmentally questionable practices currently being employed in field operations.
This report describes the field trial in Chenango County New York conducted by the Texas A&M Desalination Program during the 3th quarter of the year 2011. The specific goal of the field trial was to develop and utilize a mobile unit to demonstrate the effectiveness of different membrane technology suitable for use with high salinity flow back brines and produced water from the Herkimer formation the brines deemed the equivalent of Marcellus Shale brine.
The several treatment techniques which have been found to be successful in both pilot plant and field tests have been tested to incorporate into a single multifunctional process train. Eight different components were evaluated during the trials, two types of oil and grease removal, one BTEX removal step, three micro-filters, and two different nanofilters. The performance of each technique was measured by its separation efficiency, power consumption, and ability to withstand fouling overall, the field trial was a success. Of the four field brines evaluated, three were treated with minimal problem. Over 6,000 gallons of brine were processed. Total power cost was approximately $1.00 per barrel of fluid treated.
Vane Pump-Another Promising Artificial Lift Form?
Authors: Wang Tongbin , Shen Zejun , Pei Xiaohan , Hao Zhongxian , Zhang Lixin , Wang Quanbin , Liu He , Qian Jie 
Published: October 2012

Abstract
In thermal production well, beam pumping lifting is still the major artificial lift form in spite of its high cost on surface equipments and huge energy consumption. In conventional progressive cavity pump (PCP), the interior stator is made of synthetic elastomer, the steam temperature is too high for it to work. For the lift in high-temperature wells, in a long time, we did not have a good solution that can balance both mechanical efficiency and high temperature resistance. We developed a new lift manner by using vane pump as the down-hole pump to lift oil to the surface. According to the down-hole conditions, we redesigned the structure of vane pump with small radial size and transporting fluids axially. As same as PCP, the vane pump lift system and its rotor is driven by a surface drive head through the rotating rod strings. There is no initial tightness between the rotor and the stator of the vane pump that are all made up of metal elements. It can resist the temperature of 250 °C and be used in high oil-gas ratio well and heavy oil well. The vane pump's flow rate is about 5 to 100 cubic meters per day, and the pressure rating can reach 20MPa. The vane pumps have been deployed in five steam flooding wells. Compared with the beam pumping unit with the similiar liquid-producing capacity, the energy consumption of vane pump is 30 percent lower. Until now, the longest operation time span is 11 mouths, and all pumps are in good condition. Maybe in the near future, vane pump lift system will become another important artificial lift form. In this paper we will discuss the design of vane pump and its artificial lift system, its benefits and case histories in details.
Key words: Artificial lift, vane pump, multiple-stage vane pump, thermal production well
Cementing Sleeve Fracture Completion in Eagle Ford Shale will Forever Change the Delivery of Hydraulic Fracturing
Authors: Ferguson Kip , Thomas Colton , Wellhoefer Ben , Ingram Stephen , Montes Matthew 
Published: October 2012

Abstract
The completion cycle for the development of unconventional resource plays, such as the Eagle Ford shale in South Texas, requires multiple hydraulic fracture stages to be placed in the horizontal section of the wellbore to effectively stimulate the reservoir. Inefficiencies in the completion design caused by conventional "plug-and-perf" (P-n-P) methodologies can increase the costs associated with the delivery of hydraulic fracturing. However, new methodologies have recently been developed to mimic the P-n-P process that allow the operator to fracture stimulate the reservoir in a more economic and time-efficient manner.
The Eagle Ford shale in Lavaca/Gonzales Counties, Texas is similar to many high-carbonate-content oil shale formations. In South Texas, the industry has a preference for cementing the lateral section for fracture stage isolation. This case study explores the successful implementation of a cemented multientry point sliding sleeve technology (CMEPT) in the Eagle Ford shale. The combination of these technologies was the first ever of its kind. This study also illustrates some of the lessons learned during the years of development of this integrated service technology.
This paper highlights the key well that successfully implemented these technologies. The Kudu Hunter No. 1H well was drilled to a measured depth of 16,302 ft with a lateral length of over 6,000 ft. The integrated service design proposed a hybrid completion design with 2,000 ft of lateral completed by means of a nine-stage CMEPT and the remaining 4,000 ft of lateral completion by means of the P-n-P method.
The CMEPT allowed the placement of ~1,840,000 lbm of premium white sand with surface modification agent (SMA) by means of 1,740,000 gal of guar-based hybrid fluid over nine stages in 22 hr, and the remaining 11 stages of P-n-P completion placed ~2,310,000 lbm of premium white sand and SMA by means of 1,940,000 gal of guar-based hybrid fluid in ~80 hr.
The stand-alone conventional P-n-P process has become a barrier to the economic delivery of fracture stimulation. This case study illustrates how the adoption of the CMEPT integrated service process provides efficiencies in the completion cycle and maximizes stimulated reservoir volume (SRV) along the well path.
Event Detection for Managed-Pressure Drilling: A New Paradigm
Authors: Saeed Saad , Lovorn Randy , Davis Nancy 
Published: October 2012

Abstract
Effective event detection has traditionally been a largely manual process, exclusively in the realm of experienced personnel, who not only continuously monitor drilling parameters but also identify the current state of operations based on this data. Owing to the large number of variables and inherent uncertainties in drilling operations today, this approach still provides one of the most reliable methods. However, as a result of the advent of managed-pressure drilling and the need to carefully control and manipulate bottomhole pressures within a specified "window," the proper diagnosis and management of well events has become even more critical. Furthermore, with the popularization of an "automated" control philosophy, this can only be fully realized with an integrated event-detection system. Because a manual approach to event detection does not provide the mechanisms required to support such a philosophy, a real-time automated event-detection system is essential.
A number of approaches have been tried in the industry to implement such an event-detection system with varying, but limited, success. The approach has typically been based on a collection of rigid and archaic logic-based statements, which attempt to overly simplify and abstract operational complexity, leading to a superficial, limited, and inefficient system.
This paper presents a new, novel, and efficient approach to a real-time, automated event-detection system for managed-pressure drilling operations. Events will be discussed and followed by a detailed description of the system, algorithms, and approaches.
Precipitation Squeeze and the Use of Modeling to Maintain Production and Extend Squeeze Life Time for Marginal Wells
Authors: Guan Hua , Davis Steve 
Published: October 2012

Abstract
Scale inhibitor squeezes are used to prevent or control scale formation in producing wells. Most studies focus on the challenges and impacts of executing squeezes in difficult environments like those found offshore in the North Sea. However, squeeze studies on land-based wells with economic challenges can also be rewarding. In difficult economic environments service companies are actively involved in developing pilot squeeze programs to increase or sustain production from marginal wells. Results from these pilot squeezes must be justified economically if the programs are to be extended to other wells or fields.
This paper demonstrates how the use of additives, the forced precipitation technique and sophisticated scale modeling programs can be successfully applied to wells that are economically marginal. The example is a two-zone, forced precipitation squeeze using additives for both pre-flush and overflush packages. Following the successful application of the squeeze package, the resulting squeeze life for this well is 12 months. Average oil production from both zones for the 12 months after the squeeze is much higher than the production for the preceding 12 months. There is no evidence of formation damage in either zone. Squeeze modeling is used to simulate and optimize this squeeze to determine if the squeeze life can be extended further. This paper illustrates a successful field squeeze using additives in a forced precipitation squeeze which resulted in improved oil production and extended squeeze lifetime in a marginal well.
Design, Qualification, and Installation of Openhole Gravel Packs: Mari B Field, Offshore Israel
Authors: Healy John , Sanford Jack , Reeves Donald , Dufrene Kerby , Luyster Mark , Offenbacher Matt , Ezeigbo Eze 
Published: October 2012

Abstract
A case history from Offshore Israel is presented that describes the successful delivery of two ultra high-rate gas wells (&gt;200 MMscf/D) completed in a depleted gas reservoir with 9⅝-in. production tubing and an openhole gravel pack (OHGP). Maximizing gas off-take rates from a volumetric drive gas reservoir that possesses high flow capacity (kh) requires large internal diameter (ID) tubing coupled with efficient sand face completions. When sand control is required, the OHGP offers the most efficient as well as the most reliable, long-term track record of performance. A global study of wells completed with 9⅝-in. production tubing ("big bore") determined that this design concept was feasible and deliverable in a short time frame while still maintaining engineering rigor. The paper will highlight key accomplishments within various phases of a completion delivery process with particular emphasis on the sand control design, testing and execution. The completions were installed with minimal issues (NPT ≈ 9%) and have produced without incident. The two wells, Mari-B #9 and #10, achieved a peak gas rate of 223 and 246 MMscf/D, respectively.
Sensitive New NMR Hybrid T1 Measurements for Gas Shale, Heavy Oil, and Microporosity Characterization
Authors: Li Lilong , Chen Songhua 
Published: October 2012

Abstract
For NMR-based formation evaluation, measurement of the longitudinal relaxation time, T1 is a preferred technique for LWD because it is less vulnerable to vibration as compared to T2 measurements. For wireline NMR logging, interpreting T1 data is simpler than T2 because T1 is not affected by the additional signal decay caused by the molecular diffusion in magnetic field gradients. Moreover, T1/T2 provides additional formation and fluid information than T2 alone. Despite these benefits, the commonly used T1 measurements may suffer from either very long measurement times using the inversion-recovery (IR) data-acquisition method or reduced sensitivity in the short-relaxation time range using the saturation-recovery (SR) method. Therefore, there is an increased interest in developing more efficient T1 measurements that have adequate sensitivity for fast- relaxing components abundant in gas shale, heavy oil, and carbonates with microporosity present.
We describe a new approach of using a hybrid saturation-inversion-recovery (HSIR) sequence that takes advantage of the higher sensitivity for the short inversion times in the IR sequence and the efficient data-acquisition feature in the SR sequence. To demonstrate the benefit, we simulated many cases representative to gas shale, heavy oil, and carbonate rocks using the standard SR and new HSIR methods. We used Fréchet distance to quantitatively determine the resemblance between the input models and the inversion results and found that HSIR is consistently better in terms of the fidelity to the model. Core measurements are also presented to support the simulation studies. It is shown that HSIR is able to differentiate signal from organic matter in shale samples from other signals, while SR method is not; it is also demonstrated that HSIR can better separate microporosities in carbonate samples than SR, while using a fraction of the time used in IR method.
Evaluation of Reservoir Connectivity from Downhole Fluid Analysis, Asphaltene Equation of State Model and Advanced Laboratory Fluid Analyses
Authors: Dong Chengli , Petro David , Latifzai Ahmad S. , Zuo Julian , Pomerantz Andrew E. , Mullins Oliver C. 
Published: October 2012

Abstract
Characterization of complicated reservoir architecture with multiple compartments, baffles and tortuous connectivity is critical; additionally, reservoir fluids undergo dynamic processes (multiple charging, biodegradation and water/gas washes) that lead to complex fluid columns with significant property variation. Accurate understanding of both reservoir and fluids is critical for reserve assessment, field management and production planning. In this paper, a methodology is presented for reservoir connectivity analysis, which integrates reservoir fluid property distributions with an asphaltene Equation of State (EoS) model developed recently. The implications of reservoir fluid equilibrium are treated within laboratory experimentation and equation of state modeling. In addition to cubic EoS modeling for light end gradients, the industry's first asphaltene EoS the Flory-Huggins-Zuo EoS is successfully utilized for asphaltene gradients. This new EoS has been enabled by the resolution of asphaltene nanoscience embodied in the Yen-Mullins model. Specific reservoir fluid gradients, such as gas-oil ratio (GOR), composition and asphaltene content, can be measured in real time and under downhole conditions with downhole fluid analysis (DFA) conveyed by formation tester tools. Integration of the DFA methods with the asphaltene EoS model provides an effective method to analyze connectivity at the field scale, for both volatile oil/condensate gas reservoirs with large GOR variation, and black oil/mobile heavy oil fields with asphaltene variation in dominant.
A field case study is presented that involves multiple stacked sands in five wells in a complicated offshore field. Formation pressure analysis is inconclusive in determining formation connectivity due to measurement uncertainties; furthermore, conventional PVT laboratory analysis does not indicate significant fluid property variation. In this highly under-saturated black oil field, measurement of asphaltene content using DFA shows significant variation and is critical for understanding the reservoir fluid distribution. When integrated with the asphaltene EoS model, connectivity across multiple sands and wells is determined with high confidence, and the results are confirmed by actual production data. Advanced laboratory fluid analysis, such as two-dimensional gas chromatography, is also conducted on fluid samples, which further confirms the result of the DFA and asphaltene EoS model.
Engineering Approach to Optimize Development Strategy in the Oil Segment of the Eagle Ford Shale: A Case Study
Authors: Stegent Neil , Wagner Albert , Stringer Chuck , Tompkins Rick , Smith Nick 
Published: October 2012

Abstract
This paper presents a case study of the implementation of an integrated engineering approach to drill, complete, evaluate, and optimize multiple sets of parallel horizontal wells in the oil segment of the Eagle Ford Shale.
Two sets of horizontal wells were drilled parallel to each other in the Eagle Ford Shale. Chemostratigraphic analysis was utilized during the drilling process to assist in understanding the placement of the horizontal wellbores with regard to the target pay interval as well as assess area faulting. This data was used in designing the stimulation stage intervals and to evaluate surface injection responses during the fracture treatments. Ball-activated fracture valves and plug-and-perf completion strategies were tested to determine whether one is superior to the other. Oil-soluble tracers were used to understand the efficiency of these different completion strategies and aided in the production comparisons. Downhole microseismic mapping was also used to assist in the completion evaluation.
The integration of various engineering data allowed for interesting conclusions about horizontal wellbore placement and the effect it has on the fracture stimulation treatments, as well as the resulting production from the comparative wells. These insights provide important information for optimizing infill drilling, well placement, and fracture completion strategies in the Eagle Ford Shale. The lessons learned were implemented on additional wells in the same field and all of these results will be discussed.
Modeling System Improves Salt Drilling Technique with Concentric Reamer/RSS, Deepwater GoM
Authors: Edwards Hal , Noort Roger Van , Clairmont Brian , Compton Molly , Davis Patrick , Fitzmorris David , Franco Mariana , Nagaraj Mahavir , Nelson Gail 
Published: October 2012

Abstract
Development of subsalt pay zones in deepwater GoM typically includes drilling long intervals of halite formation. Despite the relatively low UCS, salt drilling presents a unique challenge due to its plastic nature and tendency to creep. These factors coupled with complex deepwater casing programs necessitate the use of hole enlargement while drilling techniques. The difficulties of HEWD in salt is further magnified in deviated wellbores where maintaining the directional wellplan becomes a key performance objective.
Using a 4D modeling program has resulted in improved HEWD ROP and directional control in salt on several deepwater GoM projects. The software allows engineers to model various RSS BHAs, optimize the bit/reamer cutting structure and prepare operating parameter recommendations tailored for the directional plan.
Well A
A Mississippi Canyon j-shaped well called for maintaining tangent at 44degrees through a 100% salt 14.5 ×16.5 interval. Using a new reamer cutting structure design with a selected PDC allowed the operator to drill 7852ft at an ROP of 54.7ft/hr. The directional objective in the 12.25×14.75 interval of the same MC well was to hold tangent at 44 degrees before dropping to 15degrees. A new cutting structure design with a selected PDC was employed on the RSS/BHA. The 6022ft interval was drilled in one-run with an average ROP of 80ft/hr.
Well B
Maximum ROP was the primary objective in an 8877ft, 14.75×16.5 section of a s-shaped well which included building and holding at 35 degrees before dropping back to vertical in 100% salt. Bit and reamer recommendations and drilling parameter recommendations to maximize ROP were developed by calibrating the data from the offset well, Well A. The new cutting structure and pre-job planning resulted in a total run ROP of 97.5 ft/hr with an average on-bottom ROP of 129.1 ft/hr, an 80% improvement compared to offset.
Unraveling the Myths Associated with Selecting Standalone Screens and a New Methodology for Sand-Control Applications
Authors: Chanpura Rajesh A. , Mondal Somnath , Sharma Mukul M. , Andrews Jamie S. , Mathisen Anne-Mette , Martin Frederic , Marpaung Fivman , Ayoub Joseph A. , Parlar Mehmet 
Published: October 2012

Abstract
Many completion engineers use laboratory sand-retention testing as a tool to select a screen for standalone sand-control applications, some focusing on prepack and others on slurry testing. Those who use slurry tests for screen selection typically do so based on the conventional wisdom that slurry testing is more challenging; thus, it represents the worst-case scenario for sand production. Furthermore, the general belief in the industry has been that metal-mesh screens with a "pore structure" are better for sand retention compared with wire-wrap screens (WWS) of slot geometry, although they are more prone to "plugging." These are just a few of the many myths that exist in screen selection for standalone screen (SAS) applications.
Recent papers on modeling of sand retention by screens of various geometries, and supported by laboratory experiments, provided the tools for predicting sand production in both prepack and slurry conditions, as well as allowing for a systematic performance comparison of various screens using the entire particle-size distribution (PSD) of formation sands (Chanpura, Fidan et al. 2011; Chanpura, Mondal et al. 2012; Mondal, Sharma, Chanpura et al. 2011; Mondal, Sharma, Hodge et al. 2011).
In this paper, we discuss and challenge many myths in screen selection for SAS applications and substantiate our findings with modeling and experimental data. The conditions under which a slurry or a prepack test would be more conservative are identified, highlighting the mechanisms of sand retention (size exclusion or bridging dominated). We demonstrate the current thinking that prepack tests are always more conservative from a sand production standpoint is incorrect. We also show that the concept that metal-mesh screens are always superior for sand retention than WWS is incorrect, highlighting the factors that affect sand production through various screens (open flow area (OFA), wire thickness, fraction of bridging-size particles in the formation sand etc.). Finally, a methodology for screen selection in SAS applications is proposed.