bluuebunny/crossref_metadata_2025 huggingface dataset:
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

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

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

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

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

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

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

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

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

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.
Multiphase Progressive Cavity Pumps Operated In Harsh Conditions
Authors: Seince L.. , Caballero D.. , Chacin N..
Published: February 2011

The multiphase progressing cavity pump, PCM Moineau HR (Hydraulically Regulated Progressive Cavity Pump), is a major improvement in the operating philosophy of the traditional PCP. By design, the volumetric pump is capable of handling solid, liquid and vapor phases. However, solid leads to abrasion and vapor to overheating and reduced life span where liquid is usually the added value in the process. Several papers have been issued at the SPE PCP, showing first the promising characteristics of this new principle on test bench and then the first industrial version in Venezuela. The learning curve associated with the failures has enabled to come up with a new design that resolves the abrasion and the mechanical weakness of the former NPCP (old name for this multiphase pump), keeping the core advantages of the multiphase design, that is balancing pressure and temperature homogeneously all along the pump, to get an optimum performance and a mucher higher runlife.

This paper presents the case story of a HRPCP installed in Venezuela with Equimavenca, running in harsh condition with heavy gassy oil, as well as the improvement performed ever since. It has been running for more than 20 months, producing 1600 to 2300 scf/sbl of gas.
Seismic Attribute Analysis Role in Reservoir Characterization - A Successful Application to a Giant Offshore Carbonate Field Abu Dhabi, UAE
Authors: Zhang Jie , El-Awawdeh Raed , Shevchek Zyg J. , Khouri Naeema A. , Jan Kamran S. , Harris Christopher E. , Reilly Joe M.
Published: February 2011

A recent reprocessing of a large Ocean Bottom Cable (OBC) seismic data set of a Giant Offshore Carbonate Oilfield in U.A.E. resulted in significant seismic imaging, signal/noise ratio, and detectability improvements of faults and horizon geometries which included new fault system sets never recognized before. In addition, seismic amplitude fidelity was improved significantly and it has been confirmed by well-to-seismic ties, acoustic impedance inversion, and quantitative attribute analysis. This paper will mainly focus on the results of the acoustic impedance inversion and porosity prediction by seismic attribute analysis and applications to field development.

Hundreds of regular wire-line and/or cross-dipole sonic logs were acquired and dozens of ultrasonic measurements from core samples were performed across the field. Data was conditioned and analyzed to understand the porosity versus impedance and other rock physics trends. A relatively narrow porosity versus impedance trend was observed in the data set, which laid the foundation for our subsequent analysis. Acoustic impedance inversion were performed by 1) well-to-seismic tie and wavelet estimation, 2) earth model building based on interpretation and well data, 3) band-limited impedance inversion and total impedance derivation. The inversion results and seismic stacks were loaded into a seismic attribute analysis package where multi attribute analysis was performed and porosity versus impedance and other attribute relationship was established. The porosity volume was then generated across the entire field based on the established relationship.

The resulted porosity volume based on the inversion results and other attributes and extracted maps from these volumes for different intervals were validated with well data where high consistency was observed. Since these volumes are layered properties not interface based reflectivity data like stack seismic, they can be directly correlated to geologic layers such as lithological unit etc. therefore they make the integration of geological and engineering data much easier. The volumes show higher resolution than regular stack seismic data and examples will be shown how this data has been used for thinner reservoir mapping, well planning, and input for geological models.
Monitoring PCPs in 500F Steam Flood Applications
Authors: Cudmore Julian , Al-Araimi Khalid
Published: February 2011

PCP technology has progressed to enable their application in high temperature environments. Typically PCP elastomers limited the temperature range for operation to approximately 150C, but the recent introduction of metal to metal pumps has removed this ceiling. Operation above 150C also provided a challenge for the downhole gauges used to monitor the pump and well performance as downhole gauge electronics designed for PCP monitoring were also typically limited to around 150C operation.

This paper discusses the introduction of permanent high temperature gauges designed for application in steam flood wells lifted by PCP. The field trials revealed various challenges and hurdles which were overcome to design a monitoring system suitable for an extremely challenging operational environment. The paper details the operational environment, challenges encountered and successful deployment of gauges monitoring wells produced by PCP’s in temperatures above 400F.
GOM Deepwater Field Development Challenges at Green Canyon 468 Pony
Authors: Weatherl Michael H.
Published: February 2011

Gulf of Mexico (GOM) deep water has proven in recent years to be one of the most prolific oil production provinces in the world. The bulk of the new reserves and production to date in this area flow from subsalt, Miocene reservoirs at fields including Shenzi, Tahiti, Thunderhorse, and others (1).

In the summer of 2005 Hess Corporation entered this arena and drilled the Green Canyon 468 ‘Pony’ discovery well. Information collected during subsequent appraisal drilling revealed significant insight into subsalt oil reservoirs which exist at depths between 28,000’ and 31,000’ TVD in this area. Geologic, reservoir engineering, facilities, and well construction studies have since resulted in a degree of clarity around the technical and economic viability of field development going forward.

Of critical importance is addressing structural uncertainty below salt across Blocks 468 and 469. To reduce this uncertainty further appraisal drilling was approved late in 2009 on the eastern flank of the field. In addition to further structural and reservoir definition, Pony 3 objectives included a more robust casing design with deeper settings and larger diameter hole sections below salt to further confirm feasibility of future production wells. The 2010 program also included the utilization of a six generation dynamically positioned drill ship Stena Forth which provided a valuable advantage versus the single activity, moored semi-submersible utilized on earlier wells.

Challenges inherent to ultra-deep wells in deepwater have been well documented in recent years (2, 3, 4, 5, 6). Hence, this paper will focus primarily on Pony well construction and deepwater field development planning. A number of key design issues will be highlighted including pore pressure/fracture gradient regression, casing design, bitumen (tar) mitigation, and salt creep mitigation. Incorporation of lessons learned and best practices from the substantial history of other deepwater operators has been a priority throughout this effort. Engineering and design in partnership with other operators is recognized as a critical element to ensure success in this challenging environment.
Casing Wear Prediction and Management in Deepwater Wells
Authors: Calhoun Bill , Sheldon Langdon , Wu Jiang , Hogan Phillip , Rutledge Kory
Published: February 2011

Deepwater Gulf of Mexico wells are generally deep and they may incorporate casing designs that provide only a single-casing barrier between the wellbore and the formation. These aspects present unique issues and risks in regard to casing wear. The extreme depths (>30,000 ft) of many wells in the Gulf of Mexico create the potential for high side loads imparted by the drillstring to the casing, even with low doglegs (1.0°/100 ft or less) in the upper part of the well. This, combined with potentially high rotating hours, particularly on exploration wells with sidetracks, creates the potential for casing wear that exceeds allowable limits.

In order to proactively manage and mitigate casing wear during drilling operations, Chevron has developed a Casing Wear Monitoring standard operating practice (SOP). Deployment and application of this SOP has proven effective. Application of this SOP indicates that casing wear can be predicted, managed, and/or mitigated with proper planning and execution.

This paper illustrates a casing wear event on a Chevron well and provides an overview of the Chevron Deepwater Casing Wear Monitoring SOP. Additionally, the paper highlights some casing wear processes, well control issues, and environmental risks that are unique to deepwater wells. Application of the casing wear prediction and monitoring procedures outlined in this paper help to ensure that the integrity of the casing is maintained during drilling operations, thereby reducing the risk of a health, safety and environment event or loss of the well due to excessive casing wear.
The Development and Application of A Novel Free-damage Fracturing Fluid pH<2
Authors: Zhang Jin , Zhang Yan , Wu Yongfu , He Xiuqing , Zhang Xinzhu
Published: February 2011

At present, water-based fracturing fluid systems are mainly polymer (macromolecule) and visco-elastic surfactant (micromolecule). Because of polymer properties and incomplete gelout, the damage to matrices and conductivity of artificial fractures will be inevitable. The surfactant-based fracturing fluid system is a micro-molecule system not to damage artificial fractures. However, it is difficult to eliminate the damages from rock debris moving and clay swelling in formation. A novel free-damage fracturing fluid system (FDFF), a cationic surfactant derived from a long chain fatty acid, has been developed and applied in Daqing oil field. FDFF can crosslink in a wide range from a strong acid to a weak acid, and its performance inherits the properties of traditional VES. Because its molecules can be crosslinked in acid, the fracturing process is simultaneously an acidizing process. The pollution to the vicinity of well, therefore, is cleaned out. Meanwhile, the damages of particle motion and plastic strain of the formation near cracks are alleviated so that the high permeability zone around artificial cracks is created. The damages induced by a fracturing treatment are completely removed. The rheology, leakoff, capacity of carrying proppant, and conductivity of FDFF together with its case studies are demonstrated in this paper.
Design of CO2 Dehydration and Compression Facilities
Authors: Kumar Satish , Zarzour Othman , King Graeme , Carbon Masdar
Published: February 2011

Abu Dhabi has been importing natural gas for domestic consumption since 2007 and at the same time has been injecting natural gas into producing oilfields for reservoir management and sequestration. An opportunity exists to inject CO2 instead and release valuable supplies of natural gas for other uses while reducing greenhouse gas emissions. CO2 suitable for injection will be available as part of Masdar’s Carbon Capture and Storage (CCS) project which will capture wet CO2 at atmospheric conditions from industrial plants and facilities, dehydrate it, compress it, and transport it by pipeline to producing oilfields for injection.

This paper presents options for dehydrating and compressing CO2 to achieve the optimum result while meeting all technical requirements. Technical and economic aspects of CO2 water content specification are analyzed and discussed along with current international practices. It focuses on challenges faced by the design team in developing water content specifications and selecting dehydration technology and methods for the Masdar CCS project.

Dense phase CO2 exhibits retrograde water condensation behaviour at pressures and temperatures used for pipeline transportation and injection. This means that CO2, unlike natural gas, can carry more water rather than less as pressure increases. Other products such as natural gas do not share this property with CO2 at pipeline operating conditions.

Pipelines in hot countries such as the United Arab Emirates (UAE) operate at higher temperatures than pipelines in North America and Europe and this enables them to carry product containing more water without it condensing. Therefore allowable water content specifications established by the pipeline industry in North America and Europe are unnecessarily restrictive for pipelines in hotter countries.

Retrograde water condensation in dense phase CO2 combined with higher pipeline operating temperatures in the UAE and other hot countries, permits higher allowable water content for pipelines carrying CO2 than is typical in other parts of the world. The specification of higher allowable water content can reduce both capital and operating costs of dehydration equipment leading to improved economics for CCS projects.
New Approach in Seismic Processing of Dual Sensor 3D OBC Data: Case Study from Shallow Marine Offshore Abu Dhabi
Authors: Mahgoub Mohamed , Obaid Khalid , Witte Johan
Published: February 2011

An important role of the geophone component in seismic OBC data is to allow attenuation of the hydrophone receiver ghost by summing geophone to hydrophone data (PZ summation). This ghost shows as a perfect notch in the seismic bandwidth which cannot be removed by filtering or deconvolution.

Early PZ summation has been the standard processing practice. However, as the geophone signal-to-noise ratio is lower than that of the hydrophone, the geophone component contributes less if summed early in the processing flow, especially in the presence of dispersive noise generated by a hard sea bottom, source generated noise, etc. In this paper an alternative workflow is discussed, in which the two components are processed separately until imaging. The workflow has significantly enhanced the contribution of the geophone component.

Post-stack refinement has shown its merits in data quality enhancement, allowing better matching of the two sensors which is essential for subsequent PZ summation. The differences in coupling and impulse response of the two sensors were corrected by deriving a reliable operator to match the common geophone stack to the corresponding hydrophone stack.

The final imaging product of the geophone component has an advantage over the hydrophone as it contains less multiples and wider bandwidth, allowing better structural interpretation. Late PZ summation has resulted in a much improved resolution and interpretability, especially at deeper target levels than the early PZ summation processing flow of the previous processing vintage.
Employing a Systematic Scientific Approach to Ensure Successful Implementation of Underbalanced Drilling Technology—Case Study
Authors: Sharma G. K. , Sharma M. K. , Lama T. , Duttagupta S. , Ganguly B. , Qutob Hani , Boutalbi Said , Villatoro Jaime , Lakshminarayanan Sunil , Kulkarni Nitin
Published: February 2011

Oil India Limited (Oil India) is considering adapting new technologies to ensure that oil and gas strategic resources are optimally explored, developed, and produced during the life cycle of their fields. Underbalanced Drilling (UBD) technology, which can achieve these objectives effectively when applied in conjunction with horizontal drilling techniques, is being considered among various options.

Accordingly, Oil India decided to pioneer the introduction of this new technology in their onshore oilfields by employing a systematic scientific approach to screen the Makum-North Hapjan Oilfield for UBD candidacy. The screening process involves detailed evaluation of reservoir, production, drilling, geology, geophysics, and operational data with risk analysis incorporated into a rigorous expert system aimed at maximizing the value of any UBD operation. The screening process was performed in two phases: a low resolution screening and an in-depth high-resolution analysis.

Phase I objectives were to evaluate and rank Oil India’s reservoirs for UBD in comparison to conventional (overbalanced) drilling techniques, compare candidate reservoirs against global database of UBD analogs and select a candidate for phase II detailed reservoir damage analysis and productivity forecast. Phase II objectives were to identify the formation damage mechanisms that are expected to occur in each of the three reservoirs and determine productivity and economic improvement of underbalanced compared to overbalanced drilling.

This paper describes the expert system methodology used and provides a discussion of the results obtained. Phase II study findings provided Oil India with confirmation that UBD could provide improvement compared to conventional drilling and completion technologies. The scope of the study also included a complete engineering evaluation for drilling and completion of a new horizontal well – underbalanced, including the use of a downhole isolation valve.
The Potential of Advanced "Look Ahead" Sensors in Complex Drilling BHAs
Authors: Sohmer M. , Reich M.
Published: February 2011

State of the art bottom hole assemblies (BHA) are equipped with a variety of directional and formation evaluation sensors. The drilling industry is used to safely navigate through the reservoir without interrupting the drilling process, evaluate the porosity and properties of the surrounding rock, identify the content of the pore space and measure the movability of the fluids in the pores. And these are only some few examples of state of the art technologies.

To date the sensors usually still look into the formation sideways out of the BHA, while the much more interesting view from the BHA into the space ahead of the drill bit is not possible yet. However, latest developments seem to indicate, that true "look ahead sensors" might be made available soon. A very promising approach deals with seismic measurements. Scientists have found practical ways to focus the seismic energy into a dedicated segment of the rock space around the sensor assembly, making a "directional view" into the formation possible. Provided, the seismic energy could be focused into an area ahead of the drill bit, the general concept for a true look ahead sensor would be on hand.

However, before a field proven commercial tool can be integrated into a full blown drilling BHA answers to a variety of open practical questions will have to be given. Where in the BHA will the sensor be positioned? How can the "event horizon" of a BHA, the space which can be reached by the drill bit, be specified?

This paper will develop a vision of the capabilities and limitations of next generation BHAs with integrated advanced "look ahead" sensors.
Validation of Numerical Model for Simulation of Drilling Discharges to Sea
Authors: Rye Henrik , Furuholt Edgar
Published: February 2011

The site survey for the location of the Trolla exploration well in the Norwegian Sea revealed numerous potential locations of cold water corals. These corals are expected to be vulnerable for sedimentation of particles and exposure to chemicals from drill cuttings and drilling fluids. How vulnerable they are for these disturbances is, however, not well known.

Numerical simulations were performed to predict spreading of drill cuttings and drilling fluids, including concentrations in the water column and sedimentation on the seabed. A monitoring program was also conducted, comprising cuttings particle size measurements, current measurements, sediment traps collecting depositing particles, sediment sampling, turbidity measurements and video observations. The monitoring program gave the possibility to compare results from the numerical model with observed deposition of drill cuttings.

The simulation results showed good correspondence with the contents in the sediment traps, supporting the validity of the numerical model.
What Does It Take To Evaluate A Potential CO2 Storage Site? The ZeroGen Example
Authors: James Simon , Garnett Andrew , Kumar Giridhar , Kumar Viren , Rao Narasimha , Trivedi Bhaskar , Gupta Arjit , Salunke Sarita , Sarkar Subhendu , Srinivasan Ashwin , Meen Prem , Doran Seán , Hall Nick , Barlas Peter
Published: February 2011

The effort, timeline and budget required for CO2 storage site characterization is often underestimated. Depending upon geology, volumes and composition of the CO2 stream to be stored, data acquisition, that may involve appraisal wells, injection tests, Special Core Analysis (SCAL), geomechanical and geochemical experiments, the timeline to conduct the site characterization may run into years and the budget required into tens of millions of dollars.

Experience in site characterization, in many different CO2 storage projects, has enabled a "roadmap" to be developed showing key decisions and work activities from initial screening through to the final investment decision. The primary focus of the roadmap is on the work scope of an integrated subsurface team, but it is part of a broader integrated set of activities which include capture, transportation, and storage elements. This roadmap has been used in the characterization of a CO2 Storage Site for ZeroGen in Queensland, Australia.

For each phase of the project, work activities are directed at reducing uncertainties to the point that key project decisions can be taken. The culmination is a final CO2 Storage Site Development Plan. Interdisciplinary risk and uncertainty assessments are key steps along the way which drive appraisal and data collection tactics. As new data is assimilated into the site assessment the work proceeds, in an iterative manner, as the views on Storage Site Capacity, Injectivity and Containment evolve. Throughout the site characterization phases, common threads, like the Monitoring Measurement and Verification strategy, are matured from an initial range of identified approaches and technologies into an Operating Philosophy.

Constant and early attention and priority is given to Heath, Safety, Environmental and Community issues throughout the work activities and milestone reviews. Besides our personal and corporate responsibility to the community and environment, establishing a strong record of safe and responsible operations will be an enabler towards public acceptance, cost effectiveness and schedule reduction for future projects. Early and constant community consultation is a critical issue to ensure public understanding and acceptance of CCS.
Analyzing Production Data from Unconventional Gas Reservoirs with Linear Flow and Apparent Skin
Authors: Nobakht M. , Mattar L.
Published: February 2011

Many horizontal wells with multiple fractures, producing from unconventional gas reservoirs, have been observed to exhibit linear flow. Often it is the only flow regime, and it can last several years. Classically, this flow regime is characterized by a half slope on type curves, when there is no skin effect. However, most of the time, a skin effect is observed in these wells (caused by flow convergence or finite conductivity in the fractures).

The existence of skin changes the shape of data points when plotted on log-log scales, and this can have a huge effect on the interpretation when using type curves. For example, a well with purely linear flow and with skin, in a reservoir that is infiniteacting, may appear like, and be interpreted as, a finite-acting reservoir, simply because of the "skin effect".

This paper discusses different methods that can be used to eliminate the misinterpretation caused by the presence of skin when linear flow is being analyzed using type curves. First, it is shown that among all the derivative and integral functions that are currently used, only DER (welltest-style semi-log derivative) and pressure integral-derivative are not affected by the skin. However, these two functions have other issues that usually make them unusable for production data analysis. DER is noisy most of the time and the process of integration often introduces errors at early times, which can significantly distort the shape of pressure integral-derivative. Therefore, an easier method is presented to analyze the production data from shale gas reservoirs with extended periods of linear flow and significant skin. This method uses the square root-time plot to remove the apparent skin effect from the data. Then the data (excluding skin) are used for type curve analysis. This simple procedure prevents potentially significant misinterpretation.
Breaker Enhancer for Crosslinked Borates: Novel Self-Generating Acid
Authors: Maley D. , O’Neil B.
Published: February 2011

Despite countless recent advances in fracturing fluids, traditional borate crosslinked guar fluids persist as a preferred fluid for hydraulic fracturing. The advantages of borate gels are numerous and include superior proppant carrying capability in difficult to fracture reservoirs, as well as high stability in high temperature and high shear conditions. However, borate fluids are not without notable disadvantages. The most obvious disadvantage is the presence of insoluble polymer residue that remains in the proppant pack after the gel has been broken with oxidizer breakers. Oxidizing breakers cleave the polymer chains at random sites resulting in a mixture of residual fragments which may remain crosslinked. These residual polymer fragments have been shown to significantly impair the proppant pack conductivity. Further compounding this problem, any residual unbroken gel at a high pH is susceptible to re-crosslinking when exposed to multivalent ions such as iron or calcium from the wellbore or formation.

Through the addition of a novel in-situ self-generating acid in combination with an oxidizing breaker, the degradation of borate crosslinked guar is notably improved. The controlled release of an acid, which is uniformly distributed throughout the gel, will lower the pH of the fluid thereby completely removing the crosslink from gel polymer fragments. This lower pH will result in an increase in solubility of the residue, improving clean-up of a proppant pack.

It has been shown that the addition of the self generating acid dramatically improves the regain conductivity of the proppant pack. Additionally the lowered pH of the fracturing fluid aids in the prevention of re-gelling upon flowback, reduces the water reactivity with water sensitive clay minerals, and aids in the removal of polymer residue from the well after treatment. Each of the mentioned benefits will aid in allowing the reservoir and conductive path to reach its full production potential.
A Conceptual study for Managing the Life of a Giant Offshore Oilfield in the UAE where Facilities and Infrastructure Mature ahead of the Reservoir
Authors: Modavi A. , Khan S. A. , Khedr O. , Muta T. , Brantferger K. , Watanabe M. , Walters J. V. , Martin W. W. , Al-Shabeeb A. N. , Al Marzouqi M. , Qotb M.
Published: February 2011

This conceptual study addresses the subject field which has a current expected operating life of more than 100 years, which exceeds the life of the existing facilities. As an alternative to continuing development with Well Head Platform Towers (WHPT’s), the concept of artificial islands holding drilling and production centers has been introduced [ref.1]. The island concept brings enormous flexibility in terms of managing future development uncertainties both subsurface and surface. The new subsurface development concepts include extensive utilization of ERD/MRC wells specifically designed and placed in conformance with geologically defined drainage areas. This strategy predicts significant improvement in plateau duration and sweep efficiency with fewer wells.

The new islands based surface plan allows a phased installation of facilities, and space provisions to expand facilities to cater for subsurface uncertainties. It also handles the remnant life issues associated with the existing infrastructure (Wells, WHPT’s, pipelines and trunklines, satellites, central complex). This includes provisions for future requirements in terms of Water Injection, Artificial Lift and Gas Injection and other EOR applications.
Alternative Methods in Preventing Asphaltene Deposition
Authors: Albannay Aamer , Masuzawa Tsutomu
Published: February 2011

Asphaltene deposition reduces oil productivity in afflicted wells and- in worst case- stops the wells from flowing due to complete plugging as a result of deposition inside the tubing. Currently, wellbore soaking and wire-line clean-up jobs are implemented to deal with asphaltene deposition. However, these operations are frequent and asphaltene continues to deposit shortly after.

Three methods are currently being evaluated to control asphaltene deposition: Control of operating conditions, inhibitor squeeze treatment and continuous down hole inhibitor injection. This paper discusses the results of evaluating control of operating conditions and the preparatory work required to evaluate the latter two methods.