bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effect of Sulfur Deposition on Rock Permeability in Sour Gas Reservoir
Authors: Xiao Guo , Zhimin Du , Li Wang 
Published: February 2011

Abstract
Reduction in pressure and temperature generally reduces the solubility of sulfur in sour gas reservoir. Once the reservoir fluid has reached a sulfur-saturated state, further reduction in pressure and temperature will cause sulfur to deposit. Sulfur deposition in the formation, induced by a reduction in the solubility of the sulfur in the gas phase, may significantly reduce the inflow performance of sour gas wells and even wells have become completely plugged with sulfur in sour gas reservoir within several months. In this paper, effect of sulfur deposition on reservoir permeability in sour gas reservoir was investigated from a laboratory perspective. A series of displacement experiments were conducted using gas sample with H2S mole concentration of 14.99% and 24.69%, rock sample of permeability of 1.37, 3.6 and 46.5 millidarcy, different flow rates of 3.25 and 12.5cc/min, and average pore throat size in the range of 0.1 to 1.0 um. Experimental results indicated that the higher of hydrogen sulfide concentration have a severe effect on sulfur deposition and subsequently the rock permeability decreased rapidly. When element sulfur grain size is more than average pore throat size, rock permeability changed strongly. Through a regression analysis, variation of rock permeability (K vs. P) was linear relation under high pressure, while approximate exponential function under low pressure. This work will help engineers evaluate accurately well deliverability in sour gas reservoir.
Application of Innovative Ceramic Centralizer for Solid Expandable Liner
Authors: Zhou Shaohua , Kamal Mansoor , Sanders Tom 
Published: February 2011

Abstract
Traditionally, solid expandable liners have been run without any centralizers due to the perceived risk involved, since typical centralizers would impose extra restrictions on the pipe body, which would require additional force to expand. Also, the centralizers may break during running in hole, which would lead to a possible stuck liner, and consequently, be a major problem of liner expansion. It’s also important to realize that there is a limited running clearance if conventional centralizers are utilized. This puts a lot of constraints on the type and availability of possible centralizers. As a result, some residual mud may remain on the low side of the hole during cementing operations, since it is not possible to rotate the expandable liner while cementing, nor reciprocate the liner after reaching setting depth to avoid possible damage of the expandable casing’s connection protection sleeves across the prevous 7 in. casing shoe or window exit. Consequently, the cement bond between the expanded casing and the formation would be limited and long-term isolation may be less than required.
Recently, an innovative ceramic centralizer was evaluated and implemented in the field. The ceramic centralizer consists of three individual pads affixed to the expandable casing 120 degrees offset to each other, with three centralizers equally spaced out along the middle part of the 38 ft expandable casing joint. The pad itself is made of carbon fiber ceramic composite material that is characterized by strong toughness. Once bonded to the base pipe it is not possible to remove it even with 180,000 lbs of force. It has a lower friction factor than casing, and is corrosion resistant. After tailoring the pad design to suit a 5½ in. expandable liner, such centralizers on cemented expandable liners were successfully run in five wells without any problem. The acquired ultrasonic image tool (USIT) log demonstrated that the cement bond with such centralizers was substantially better than the case without the use of any centralization.
Management of Water Injection Quality in a Giant Carbonate Onshore Oil Field, Abu Dhabi, U.A.E
Authors: Stenger Bruno A. , Al Katheeri Abdulla B. , Al Kendi Salem H. , Elabed Amjad 
Published: February 2011

Abstract
This paper reviewed the management of injection water quality in a super-giant carbonate oil field operated by ADCO onshore Abu Dhabi since 1973. This field was subjected to peripheral water flooding in order to maintain reservoir pressure and provide a mechanism to sweep the oil. Injected water was sourced from 23 water supply wells completed into deep hyper-saline aquifers with total suspended solids (TSS) of 1.5 mg per liter (mg/l). Each water supply was connected to a cluster of 4–5 water injectors. Clusters were interconnected.
Produced water having average TSS of 100 mg/l and oil in water (OIW) content of 260 parts per million (ppm) was being reinjected into the most permeable reservoir through five well peripheral pilots injector. No significant operational problem was reported apart from occasional injectivity degradation which was restored with a maximum of one acid stimulation per well since 2002. New facilities under construction were designed for a maximum OIW of 100 ppm with plans being made to reduce it to 50 ppm as the volume of produced water was expected to rise with the field wide implementation of gas lift.
After more than 30 years of production from two major high-quality reservoirs, ADCO recently started the development of a third oil-bearing Reservoir X classified as low permeability. Accepted assumptions based on the extensive water injection experience proved questionable considering the low median pore size diameter of the reservoir under development. The common water supply for the peripheral water injectors assigned to the three different oil-bearing reservoir zones posed an additional challenge as the water injectors drilled in the low permeability reservoir needed to be shielded from temporary degradation of water quality typically experienced during start-up operations after maintenance or water supply well workover.
The issue of temporary high solid loading gained importance as the practice of discharging water loaded with solids to a pit was discontinued after 1998 for environmental reasons. Several studies related to water quality were recently performed including the onsite cycling of aquifer water through reservoir core plugs of Reservoir X in order to predict the potential degradation in matrix injectivity over time and evaluate the resulting operational cost and timing of future acid stimulations. Material selection for the surface pipeline network carrying the aquifer water was also reviewed with non-metallic internals being recommended. In the event of a temporary degradation of water quality following system start-up or a workover in a water supply well, disposal of such water into the source aquifer was determined to be the best solution to avoid injecting water loaded with solids in the low permeability reservoir, also fulfilling all regulatory requirements.
Improved Description of Shallow Shelf-carbonates with Resistivity-based Imaging While Drilling, Abu Dhabi, U.A.E.
Authors: Clark Andrew , Stenger Bruno A. , Vahrenkamp Volker , Dayyani Taha Al , Souliman Abdullah 
Published: February 2011

Abstract
This paper presents the experience gained with resistivity-based imaging-while-drilling (IWD) in a recent three-well horizontal drilling campaign in a giant onshore reservoir of the United Arab Emirates. The campaign highlighted that optimal drilling parameters were required to produce optimum results from the IWD technology, namely: careful bit selection and bottom-hole assembly, constant weight-on-bit, use of mud additives and real time monitoring for a continuous adjustment and optimization of drilling parameters. Experience from this campaign confirmed that good quality image logs could be acquired while drilling, providing time and cost savings without sacrificing detailed reservoir characterization. As with any new application, acquisition parameters and tool set-up had to be fine-tuned for the specific downhole environment
The 5000ft-long horizontal IWD in well W-480 shows laterally continuous clusters of distinctive Lithocodium/Bacinella bioherms in the economically important A3 reservoir layer in Field-W. Bioherms are distinct in reservoir character with high porosity and a connected macro pore system. They are typically 10-30 ft in width (with a range of 5 to 100 feet) with an inter-bioherm space of typically 1 to 3 feet. This lateral continuity of the ASFB lithofacies with its distinctively higher average permeability compared to the other reservoir facies (SPWP and FSW) found in the Thamama A reservoir, further supports the current Zone-A FDP strategy of initially restricting water injection to this subzone only.
A significant number of faults and fractures could be identified in all three wells. The more extensive presence of fractures in Zone-A supports recent observations from cores that fracturing is probably more pervasive in this field than previously assumed. At least one fault clearly identified from IWD logging was conclusively correlated with the 3D seismic interpretation.
Reservoir pressure fall-off tests and water flow log analysis from water injector w-480 indicated that more than half of the horizontal wellbore length could be considered "effective" for fluid injection. Furthermore, the large storativity ratio indicated that despite the extensive fracturing, a dual porosity system linked to the matrix properties of the biohermal ASFB facies is present in subzone A3. Results of two pressure fall-off (PFO) tests acquired in this water injector were repeatable and supported the presence of a dual porosity system, the relatively high proportion of a secondary porosity system being consistent with a vuggy algal boundstone facies as opposed to a fracture system. The impact of this finding on reservoir performance was being evaluated at the time of writing.
Advances in Seismic Processing Yield New Insights for a Giant Onshore Oil Field, Abu Dhabi, UAE
Authors: Mahmoud Sabry L. , Hadidi Mohamed T. , Grausem Marc , Al-Haddabi Ali 
Published: February 2011

Abstract
In 1997–99, Abu Dhabi Company for Onshore Oil Operation (ADCO) acquired and processed a 96-fold 3D seismic land survey over one of its giant onshore oil fields. Subsequent interpretation work highlighted the need to improve seismic data quality to better image fault corridors that were identified and mapped across the field. Attenuation of multiples and other types of coherent and incoherent noise and mitigation of the impact of the near-surface layer on statics and amplitudes were identified as key areas for improvement. Consequently, the 1999 3D seismic survey was reprocessed in 2009 with the aim of improving the signal to noise ratio and enhancing resolution of the reservoir interval with a special focus on strike-slip faults and related features such as fault displacements. Advanced and careful processing, including elastic modeling and adaptive subtraction of surface waves, wavelet processing, several iterations of static solutions, and surface-related multiple attenuation helped achieve optimum quality of the final seismic image. Additional seismic outputs such as angle stacks, image gathers and azimuthal stacks were also produced for the purpose of performing advanced geophysical interpretation work such as seismic anisotropy analysis, inversion and AVO. Preliminary analysis of azimuthal volumes in a pilot area gave indications of seismic anisotropy related to the main directions of faulting trending N75W and N45W. Seismic reprocessing sharpened the imaging of strike-slip faults and clarified depositional features in the southern part of the field. Coherency extractions were also successful in imaging strike-slip fault extensions. The new seismic images were of substantial benefit to ADCO’s program of drilling horizontal wells targeting thin reservoir intervals of 10 feet thickness or less. Prediction of potential faults and their associated throws was critical to ensuring correct well placement during the design and drilling phases.
Maximizing the Marcellus Gold Rush While Minimizing Negative Impacts
Authors: Huls B. 
Published: February 2011

Abstract
The Marcellus Shale, often referred to as "America's next super giant," has generated considerable interest in the Northeastern United States. Producers are leasing vast acreages, drillers are converging from across the nation, and service companies are mobilizing in force. Jobs are being created with local businesses benefitting from the increased activity associated with extracting shale gas. While technological advancements in horizontal drilling and hydraulic fracturing have allowed for a footprint significantly reduced from years gone by, and despite positive influxes of revenue, development of the Marcellus Shale in the Appalachian Basin is not without controversy. The speed at which the Marcellus is being developed, coupled with the lack of understanding by the public about a domestic fuel source long taken for granted, is creating a tension over how best to maximize the Marcellus Gold Rush while minimizing the negative impacts on the local environment.
The Marcellus Shale lies amidst some of the largest blocks of contiguous forests east of the Mississippi. More than 72 percent of the Susquehanna River Basin sits above the Marcellus. Consumptive water use to fracture a horizontal well can be in the millions of gallons. Unfamiliar chemicals are being transported and operations continue around the clock. There is no history of activity like this in the modern age in this region. Community groups have formed on both sides of the issues, while government agencies have ramped up their efforts to monitor extraction and consider the Marcellus as a new revenue stream for deficit-ridden state budgets.
This paper will address environmental concerns associated with Marcellus Shale development and explore positive solutions to mitigate local conflict and enhance cooperation. The exigency of addressing issues in the development of this new resource from an industry perspective as well as the local economic and environmental impacts will also be examined.
Liner Drilling with Multiset Hanger and Retrievable BHA
Authors: Moffitt Michael , Eriksen Erik 
Published: February 2011

Abstract
Drilling with liners has long been recognized as a potential solution to problems in oil and gas wells that are associated with drilling conventionally and running a liner to cover the interval in two separate steps. The most prevalent problems are covering time-sensitive formations with pipe prior to the hole sloughing in, and the detrimental effects of swab and surge when running tools into and out of open hole, leading to potential well control and casing/liner installation problems.
Basic drilling with liners incorporating a bit made up to the end of the liner and then drilled to total depth helps solve these issues, however, sacrifices the ability to run more sophisticated tools in the bottom hole assembly (BHA). Also, traditional liner top equipment was neither designed to endure the rigors of drilling dynamics, nor the balance of minimizing the equivalent circulating density (ECD) in the drilling mode while maximizing the performance characteristics related to the mechanical properties of the liner top equipment.
The ability to reliably overcome the above problems has been accomplished through the careful design and construction of a purpose-built liner drilling system. Specific consideration has been taken to balance the high bypass necessary for ECD reduction during both drilling and tripping operations, yet provide high burst, collapse, and tensile capacities of the liner top equipment while maintaining full drift through the tools. The system also allows for multiple BHA change-outs while leaving the liner parked in tension anywhere in the parent casing.
This paper covers the drilling tests that have been performed with a liner system purpose-built for drilling applications with sophisticated BHAs that require the ability to be returned to surface for change out due to worn or malfunctioning equipment or once total depth is achieved.
Deepwater Wellbore Cleanup System
Authors: Hern Gregory 
Published: February 2011

Abstract
In deepwater and extended-reach wells, good system hydraulics are important for providing maximum annular velocity needed to prevent debris from settling on the low side of the hole. Historical data indicates that as much as 30% of nonproductive time during completions is the result of debris left in the wellbore. Wellbore cleaning systems are used to reduce nonproductive time by effectively removing that debris. A new system of deepwater wellbore cleanup tools has been developed, which features high torque and tensile ratings, new bearing technology for high rotation speeds, and bigger flow areas.
New scraper and brush configurations are more durable and provide an improved method to clean the casing. A new magnet configuration can capture and retain a larger volume of debris. Additionally, a new filter configuration improves the ability to capture and filter debris. Multiple operations can be performed on a single run, thereby further reducing rig time. This is accomplished by running several high-performance tools that can scrape and brush the casing ID, collect and remove debris from the well, filter the wellbore fluid, and displace drilling fluids with completion fluids. These tool enhancements, which are implemented in this new suite of tools, improve reliability, reduce operational risk, and allow the tools to operate more efficiently as a system.
Two Issues in Wellbore Heat Flow Modeling along with the Prediction of Casing Temperature in the Steam Injection Wells
Authors: Bahonar M. , Azaiez J. , Chen Z. 
Published: February 2011

Abstract
Although several models to determine the formation temperature in the modeling of thermal production and injection processes have already been suggested, there is no rigorous or systematic comparison between these models’ predictions that can guide the choice of the most appropriate one. Another issue in thermal wellbore simulators is the commonly used assumption of steady-state heat transfer from the wellbore up to the cementing/formation interface. The effect of the steady-state assumption versus the unsteady-state assumption for the heat transfer from the wellbore up to the formation has not received much attention in the literature and can be important in some cases.
The results of a detailed analysis of above two issues can be implemented in all thermal wellbore and reservoir simulators to increase their accuracy.
The above stated issues will be addressed in the present work by developing a numerical non-isothermal two-phase wellbore simulator coupled with tubular and cement material; and surrounding formation. The first issue will be studied in detail by comparing five different models for the formation temperature treatment (FTT) plugged in the developed thermal wellbore simulator. Investigation of the second issue will be achieved by analyzing the three critical items: First, a 2D heat transfer PDE model of the formation is discretized in a general form; second, the gridding system is shifted from the formation towards the casing; third, an effective specific heat capacity for the casing is used. The effects of choosing different models for FTT and using either the unsteady-state or the steady-state assumption in the heat loss from the wellbore up to the formation will be investigated. The model will be validated against field data to show its merits in predicting the casing temperature.
The entire wellbore system contains wellbore, tubing, insulation, annulus, casing, cementing, and formation. A fundamental understanding of this system is still a challenging issue in the petroleum industry, and its accurate modeling and coupling with reservoirs has become increasingly significant as more energy resources are sought.
Enhancing Well Productivity in a Tight-Gas Formation with an Aqueous-Based, Surface-Modification Agent: Laboratory Study
Authors: Nguyen P. D. , Weaver J. D. 
Published: February 2011

Abstract
Coating proppant with a surface modification agent (SMA) provides cohesion between grains resulting in the formation of proppant aggregates. This paper presents the development of a new SMA that is aqueous-based and includes results obtained from a laboratory study. The new, aqueous-based SMA material (ASMA) provides significant improvements in health and safety, ease of operation for the treatment of proppant and formation surfaces to control proppant and fines production, and moderation of diagenetic reactions that reduce proppant strength and permeability. Potentially volatile, combustible solvents used in the delivery of conventional SMA are not required with this new agent. This results in reduced flammability and volatile organic compounds and is easy to cleanup with water, eliminating the need for harsh solvents.
ASMA can be directly substituted for SMA in all normal applications and laboratory results indicate similar performance. A unique property of ASMA is that the rate of release of the active SMA ingredient can be controlled. This permits applications where it can be added directly to aqueous frac fluid during a treatment to treat proppant rapidly, or to the prepad to treat the formation face as it is created in a delayed fashion. It can be injected into an existing proppant-packed fracture to treat proppant and formation faces in a remedial type treatment, particularly following an acid stimulation to remove fines damage.
The Use of Downhole Drilling Parameters Combined With Surface and Downhole Mechanical Specific Energy Data Helped Identify Under-Reamer Dysfunctions in GoM Deepwater Projects
Authors: Thomson Ian J. , Mathur Rohit 
Published: February 2011

Abstract
It is well known in the industry that drilling and under-reaming can be very demanding. Destructive vibration is one of the main concerns, especially when drilling through interbedded formations. In today’s Gulf of Mexico (GoM) deepwater market, in order to reach greater depths and overcome narrower operational mud window, well construction design typically accounts for multiple casing strings, thus the use of concentric under-reamers has become almost mandatory.
In the last three years, much work has been done by service companies and operators to better understand bit and reamer synchronization along with bottomhole assembly (BHA) design and modeling. These are essential aspects for successful under-reaming runs although, in some applications, severe vibration still prevails. When that happens with an under-reamer in the BHA, it is hard to identify whether the source of vibration is the bit, the under-reamer, the BHA, drilling parameters, or a combination of all. A solution for the problem is elusive since, in many cases, the source has yet to be identified.
The use of downhole drilling dynamics data along with downhole drilling parameters, measured and transmitted in real time by a specialized drilling optimization tool, in combination with the proper use of surface and downhole mechanical specific energy (MSE) data has proven to be effective for identifying under-reamer’s drilling dysfunctions, which could not be identified solely with the use of surface drilling parameters.
This paper will present GoM deepwater project case histories where the use of the downhole drilling data optimization process was used in both real-time and post-well analysis. Emphasis will be on how the data was analyzed and how the learning’s were applied to optimize the operations and improve performance.