bluuebunny/crossref_metadata_2025 huggingface dataset:
Sourceless Porosity and Permeability Estimation with NMR Logs While Drilling in a Carbonate Reservoir: A Case Study
Authors: Serry A. M. , Al-Mutwali O. , Al-Mansoori A. M. , Al-Marzouki M. I. , Budebes S. A. , Gueddoud A. G. , Balliet R. , Aki A. C. , Akopyan G.
Published: December 2013

Sourceless porosity estimation has become more attractive because of evolving government regulatory and HSE requirements. The use of wireline nuclear sensors and their HSE procedures have a 50-year history, while nuclear sensors for logging while drilling share the last 20 of those years.

Recently, the potential of using non-nuclear methods for porosity estimation has been explored in an offshore Abu Dhabi carbonate sequence. This paper presents a case study of nuclear magnetic resonance (NMR) logs while drilling, in comparison to conventional density and neutron logs using radioactive chemical sources. NMR T1 porosities were also compared to laboratory core results. Two approaches are investigated: Estimated hydrogen-index correction to NMR moveable-fluid volume using core-normalized porosities.An insight into an integrated NMR-acoustic approach, using the two sensor measurements to derive a corrected porosity.

A workflow is proposed for optimized job planning, operational procedures, data-acquisition parameters, and interpretation techniques. Permeability estimation with NMR is discussed, and a selection of methods are considered and contrasted to laboratory core permeability and wireline formation-tester results.

This paper explores the potential for sourceless porosity measurements through NMR and acoustic/NMR measurements in an offshore Abu Dhabi carbonate sequence in compliance with the HSE standards and government regulations, where the need for reconsidering reservoir characterization through sourceless porosity options will continue to grow.
Upstream Data Standards at Saudi Aramco
Authors: AlShehry M. A. , Al-Khudiri M. M. , Al-Sanie F. S. , Miyajan R. A. , AlTaiban A. A. , Al-Zawawi A. S. , Khakwani M. S.
Published: December 2013

This paper describes the upstream data standards that Saudi Aramco has recently implemented for Drilling and is in progress to implement them for other areas such as Production and Reservoir Characterization. These standards enable us to make wider use of our monitoring and collaboration centers through a common approach. It also allows us to leverage the evolving WITSML, PRODML and RESQML standards more effectively in our upstream operations.

Saudi Aramco relies on many service organizations to deliver the generated data which requires common and standard data classification when exporting data from source A then importing to destination B. Applying a common approach to information access on a global basis has enabled us to streamline our operations and make wider use of emerging analysis, monitoring and collaboration technologies.

Real-time technologies have been utilized to capture, monitor and analyze operational data from well sites so that critical decisions can be made in real-time to reduce and eliminate operational and safety problems, thus reducing non-productive time. That includes high-tech rigs, smart wells, monitoring & collaboration tools and real-time data visualization systems.

Our aim has been to implement standard upstream information architecture. Our full implementation of WITSML was the vehicle which allowed this to happen in Drilling & Workover operations. We still believe that over the next years with the advancements of technologies there will be more challenges to support open connectivity between different vendors and services supporting the increasing upstream functions.
A Pragmatic Approach for Promoting Local Proppant in International Business
Authors: Das Prasanta , Kothamasu Ramya , Karadkar Prasad
Published: December 2013

Because hydraulic fracturing applications are booming, the market availability of proppants plays a more significant role in the global oilfield economy. As a result, the demand for commercially manufactured proppants is increasing, fueling the construction of new production facilities around the world. Currently, there are only a handful of well-known suppliers of manufactured proppants that dominate the business globally.

This paper discusses a systematic approach to highlight and promote local proppant suppliers in international markets outside North America. This paper discusses how local suppliers from different regions within the Eastern Hemisphere were contacted for prequalification samples of their proppants. Submitted proppant samples were categorized, and a quality control (QC) method was established. Tests were performed as per ISO 13503-2 (2006) to pass the quality check. Comparisons, in terms of crush resistance and conductivity, were made between the products of standard international proppant suppliers and the local suppliers. Consistency and repeatability of the samples from different lots were measured; eventually, some of the vendors were certified to be a regular proppant supplier. A cost analysis was also performed to demonstrate how using local proppant could be beneficial.

This paper demonstrates in detail the procedure and testing cycle for establishing a local supplier in the Eastern Hemisphere, and then the global marketplace. A case study is included that illustrates the volume of proppant shipped for a specific area of field applications and the cost savings gained. A significant economic advantage was achieved because of the local availability of standard-quality manufactured proppant. The promising results of this study should encourage local suppliers to invest into the business and help convince the industry that more economic alternatives are available to meet the market demand for manufactured proppants.
Quick Gas Production Increment by Optimization of Pressure Control Valves on Gas Condensate Wells. A Field Case in Saudi Arabia.
Authors: Rodriguez Ruben Villegas , Jauregui Jairo Leal , Bolarinwa Simeon , Al-Driweesh Saad , Al-Buali Mustafa , Dhamen Mohammad A.
Published: December 2013

Evaluating pressure drop changes across Pressure Control Valves (PCVs) is a key element for identifying potential gas incremental opportunities and determining potential energy loss in maturing gas fields. This is more critical when the gas reservoir is being depleted without a pressure maintenance suport program. A dedicated production tracking and monitoring process is required for a full evaluation of every component in the gas production system; from downhole to the gas plant.

Operational data and choke valve erosion velocity calculations from 60 gas producing wells were evaluated to identify PCV’s needing replacement and optimize production strategy. These wells were experiencing high PCV pressure drops, constraining their ability to produce at maximum potential. Factors such as Cv; internal damage or plugging were evaluated to determine the cause of the under sized PCV’s. Additional efforts were required to verify the sizes of installed PCV’s and to ensure that flow rates could be properly calculated by recalibration of instrumentation and validation of venturi meter calculations. A PCV replacement program was then established to maximize the productivity of seven (7) critical high producing wells.

This paper describes the multi-disciplinary approach and methodology implemented in North Central Ghawar Gas field to optimize the performance of installed gas well pressure control valves. This methodology will continue to be implemented and expanded to cover more than 500 wells in other Saudi Aramco gas fields.

The paper discusses additional topics such as: proper design and metallurgy of pressure control valves, new evaluation model for pressure control valve flow equations, gas rate validation, building PCV simulator model using dedicated well performance tools, screening tools and an economic model.

Implementing this program is essential to maximizing gas rates and optimizing field production by identifying undersized PCV’s that need to be sent to the shop for internal inspection and maintenance or replacement.
Implementing Water Flood in the Greater Burgan Field, Kuwait: Improved Development Planning Through Pilot Testing and Field Appraisal Activities
Authors: Rajan S. , Al-Naqi M. , Al-Humoud J. , Ameen A. A. , Al-Qattan M. N. , Al-Hashash H. H. , Al-Enizi N. , Madhavan S. , Al-Qattan A. , Brooks A. D.
Published: December 2013

The Greater Burgan Field is the largest clastic oilfield and the second largest oilfield in the world. First discovered in 1938, and developed from 1946, production to date has relied on primary recovery methods. More recently secondary and enhanced recovery techniques have been investigated and water flood is now at an advanced state of implementation. The first such water flood project is being implemented in the Upper Cretaceous (Cenomanian) Wara Formation, which is one of the main producing reservoirs within the Greater Burgan complex. Here, production has been accompanied by steadily declining reservoir pressure.

The Wara Formation comprises multiple sandstone units deposited in a fluvial-tidal coastal system with a total thickness of approximately 140 – 180 feet. The reservoir exhibits a considerable degree of permeability heterogeneity. Lateral and vertical extent, and the pressure communication between sand bodies is highly complex. Understanding of hydraulic connection and volumetric sweep are therefore one of the key development challenges to address in this complex reservoir.

To avoid costly water disposal and to make best use of available resources the full field waterflood will re-inject produced water. Therefore project planning required an assessment of water injectivity using several water sources and an investigation of the required water quality requirements for the full field water flood.

A peripheral waterflood configuration has been selected for Wara reservoir taking advantage of some 1200 feet of vertical relief between the flanks and crest of the anticlinal structure. Prediction and optimization of this waterflood project required appraisal of structure, pressure, reservoir quality and fluid type in largely undrilled lower flanks areas.

This paper summarizes the pilot waterflood projects, flank appraisal activities and related study work to understand hydraulic connection, reservoir properties, injectivity and reservoir performance. It describes the approach taken and the learning points from each of the activities together with their implications for the full field water flood project.
Logging While Drilling Resistivity Images for Geosteering
Authors: Bazara Magdi , Maalouf Janine , Al-Sharafi Mohamed , basyouni Adnan , Farah Ahmed , Bulushi Waleed
Published: December 2013

Petroleum Development of Oman (PDO) is undertaking a waterflood development of one of their fields. This project requires drilling horizontal wells in heterogeneous carbonate formations. The water injection wells are planned to be drilled in the lower part of the reservoir which has high porosity and water saturation of minimum 40%.

Azimuthal density images have always been the approach for real time formation evaluation and steering. However, for this project, the operator has selected the high resolution LWD resistivity images due to their closer position to the bit, as well as their better stratigraphical resolution.

This shift in technology was due to the need for making proactive decisions and to address structural complexity of the targeted layers.

The resistivity images allowed readjusting the well path during geosteering. It helped precisely evaluate the dip of the formation, when even one degree can affect drastically the length of the reservoir exposed for production.

On a geological level, the resistivity images permitted the interpretation of features that could not be easily detected with other technologies. Different categories of faults, fractures and bed boundaries were detected, first time in this particular layer with an LWD technology.

The use of high-resolution resistivity images allowed optimal placement of the well in a more focused target (thinner zone for the entire drain section) and a better understanding of the geological environment. This not only helps in updating the overall field model of the client but also means improved strategic planning for better results in future wells.
A Field Trial to Assess Asphaltene Related Production Impairment—Marrat Reservoir, Magwa Field, Kuwait
Authors: Al-Qattan A. , Chimmalgi V. S. , Dashti H. H. , Haryono R. , Snasiri F. , Abdulla F. A. , Al-Humoud J. , Bond D. J.
Published: December 2013

Asphaltene deposition in the reservoir, wellbore and facilities has long been recognized as a problem in the Marrat reservoir in the Magwa field, Kuwait. One option of avoiding asphaltene problems in the reservoir, including the near wellbore region, is to maintain reservoir pressure and flowing BHPs above the asphaltene onset pressure (AOP).

Given that there is a large pressure difference between AOP and the bubble point pressure and that natural flow is possible at pressure well below AOP, there may be economic benefits in operating the reservoir at pressures below AOP. Benefits relate the reduced and delayed costs of water injection facilities. There may also be some additional recovery related to fluid expansion.

Potential problems relate to possible adverse changes to relative permeability due to asphaltene related wettability changes, productivity impairment due to near well-bore asphaltene deposition and increased asphaltene problems in the wellbore. The second and third of these potential problems have been assessed by a field trial.

This paper describes the selection of a candidate well and the design of a field trial to assess these problems. The selected well was produced first with FBHP well above the AOP. Asphaltene deposition in the tubing was monitored, fluid samples were taken and pressure transient tests were performed to diagnose well inflow performance. No decline in well productivity was seen in this period. Asphaltene deposition in the tubing was a problem and the well required cleaning during this period.

The well was then produced at high rate, with flowing BHP well below AOP and a similar surveillance program was carried out. Finally the well was returned to low rate production.

Analysis of the data from the high rate and subsequent low rate production periods indicated that there had been a limited decrease in well productivity. These data also showed that asphaltene deposition in the tubing was less of a problem during the high rate test than during the preceding low rate test.
Impact of New Wide Azimuth Seismic in South Oman on Development Decisions
Authors: Al Jahdhami Nafa , Healey Martin
Published: December 2013

The acquisition of new wide azimuth (WAZ) seismic data in South Oman has enabled improved subsurface imaging. Interpretations of these data have enabled optimal development decisions by ensuring wells are located optimally or not drilled.

The WAZ data was acquired in 2010 with a super crew operating in different terrain types in a 24/7 mode over a period of 13 months, covering a total surface area of 3,800 km2 and making this the largest ever recorded in PDO history. The data is currently being processed through a series of phases from Post Stack Time Migration, Pre Stack Time Migration to Pre Stack Depth Migration. Even early initial volumes of the Pre Stack Time Migration (PSTM) have already impacted development and appraisal drilling decisions on a deep carbonate field and the possible placement of future development wells on other fields.

The Pre Cambrian carbonate reservoirs at depths of 4500 km below the surface are not clearly imaged by conventional 3D seismic data, but now have been significantly improved by the WAZ data. New interpretation of these data has helped save the cost of at least one deep well that was initially planned. The new interpretation now enables a realistic match of material balance and simulation models with current production. In addition to the improved imaging and resolution of the deeper seismic events, the WAZ has also improved mitigation of the structural uncertainties of these reservoirs in areas where faults were previously not imaged by the conventional 3D seismic data.

The impact in this case was on the placement of previously planned miscible gas injectors and production wells in the field.
Oil Recovery Options for Waste Water Treatment Facilities
Authors: Al-Mebayedh Hamad
Published: December 2013

The ultimate goal of this study is to develop an environmentally and economically sound technology to manage and recover oil from waste water treatment facilities by studying the behavior of oil in water particularly at waste water facilities in Kuwait. The information available is diverse and widespread. Despite the necessity for such information, there’s no paper in the literature concerning the fate and behavior of oil in water concerning Kuwait’s environment. The actual frequency, magnitude, and consequences are unknown, which has proven to be a serious problem for the environment waste management in Kuwait’s Oil industry. Hence this Study attempt to correct that informational void by presenting waste management techniques, solutions, the behavior of oil in water within waste water facilities areas in Kuwait.

The methodology adopted was performed by carrying out a review of existing literature, contacting companies previously involved in recovering oil from water worldwide, holding discussions with operators, this is then applied to ADIOS2 the Automated Data Inquiry for Oil Weathering Model to develop the ideal scenario.

In a completion of this study we extrapolate that, Most of the existing mechanical recovery equipment was designed to collect oil using its property to adhere to the surface material of the recovery unit. This equipment can efficiently collect oil with certain physicochemical properties at standard conditions and cannot be used with equal competence both in warm and cold waters and on variable oil types and properties. The recovery efficiency significantly changes with time due to the oil slick property changes and emulsion formation. Therefore, multiphase interactions between oil, water, material of recovery unit need to be studied thoroughly due to their strong influence on the oil recovery process.
Well Integrity Management System (WIMS): Coupled Engineering Analysis
Authors: Samuel Robello
Published: December 2013

Managing well barriers and maintaining well integrity within limits is challenging for aging wells and has a major effect on extending the life of wells and reducing operational costs. This is important for both the design phase and the operational phase. As more real-time data become available, the efficient use of quality data for analysis has become important. Little has been done to include some of the important engineering analyses in this process. Standard methods and guidelines are traditionally used before or after they occur, but the key to savings and success is avoiding the risks associated with them. If risks are identified early, better solutions can be provided to reduce the associated costs and take remedial action. This paper will present the importance of engineering analyses, such as wellhead movement, trapper-annular pressure buildup, maximum allowable surface pressure, temperature and pressure effects on the integrity, casing wear, corrosion, and erosion significance, as well as zonal isolation and estimation of the tubing or casing safety factor as a quantifiable monitoring system. The presented threshold limits help to compare the actual and average values, either on a single-well or multiple-well basis in an asset. Continuous monitoring helps identify the risk involved with engineering analysis rather than setting simple limits and following the workflow process.
Downhole Analysis and Laboratory Analysis, Key Complementary Techniques for a Comprehensive and Effective Fluid Characterization
Authors: Al-Sabea S. H. , Al-Rushaid M. A. , Mohamed A. A. , Bouchet F. D. , Harami K. K. , Al-Khabbaz M. J. , Slimani K. M. , Jamal S. , Ayyad H. A. , Aguilera P. R.
Published: December 2013

Downhole sampling and laboratory analysis are key complementary techniques offering a step change in fluid characterization. It is generally accepted that fluids in the reservoir are in chemical equilibrium. However this assertion, although convenient, is often invalid, for several reasons from source variations, due to in-reservoir reaction, degradation or precipitation. In a large majority of cases many of these phenomena are difficult to appreciate, because the techniques used for fluid sampling often lack the pin-point acquisition accuracy (geographical, depth and time) required to provide the information at a level of accuracy sufficient to detect subtle variations. Instead only a mixture of different oil is captured providing "averaged" oil composition and characteristics, whereas the reality in the reservoir may be markedly different. The vertical compositional gradient in oil column has been documented in many large oil column reservoirs. The geographical variation has been much less documented. In this paper we will demonstrate how variation at the scale of individual sand bodies in the reservoir, sometimes only tens of feet apart, can be very large (as observed in two sand bodies in the same well) and have a dramatic impact on oil property understanding and modeling. In turn understanding of these property variations and their impact on mobility, is a key factor for understanding fluid flow and for the choice of the correct secondary recovery mechanism for an improved recovery. The example of the Wara channelized sand, within the Greater Burgan complex, will illustrate the paper, where downhole fluid analysis is presented as a necessary complementary tool to improve the selection and construction of an accurate set of samples to ensure the data collection is complete and exhaustive before the well is completed.
Overcoming Design Challenges of Chemical EOR in High-Temperature, High Salinity Carbonates
Authors: Levitt David , Klimenko Alexandra , Jouenne Stephane , Chamerois Manuel , Bourrel Maurice
Published: December 2013

The optimization of chemical floods for a low-permeability, high-salinity, high-temperature carbonate formation presents several unique design challenges, which may be overlooked in short coreflood experiments. Low permeability formations require the optimization of polymer molecular weight distribution such that both mobility reduction and injectivity are maximized. The effects of high core-scale heterogeneity must be understood and mitigated, for example, by increasing core length. These subjects are explored in the context of an ongoing flood design project. Understanding and mitigation of pressure build-up issues – possibly related to high surfactant adsorption – is an ongoing challenge. Additionally, an attempt will be made to shed light on the discrepancy between available carbonate capillary desaturation curves for carbonates and the near-complete recovery reported in surfactant-polymer corefloods.
Does your ESP Completion Architecture Meet All Your Production Requirements?
Authors: Camilleri L. , Gambier P.
Published: December 2013

The first electrical submersible pumps (ESPs) were installed nearly 100 years ago by simply running an ESP on tubing in a cased hole. Since then, ESP completion architectures have evolved to cater for a wide range of needs such as dual barriers for offshore operations, reservoir monitoring, flow assurance, backup gas lift, back-allocation for multilayered reservoirs, and dual ESPs for enhanced run life to name a few. These solutions have been made possible by new completion tools which continue to be developed. However, the biggest driver behind the proliferation of completion architecture arrangements has been the creativity of field engineers to meet production and operational needs. Key to justifying additional complexity in a completion is to demonstrate the value, and, to this end, an exhaustive list of functional production and operational requirements was developed and reviewed to serve as a check list for evaluation of artificial lift completion architectures. Establishing the requirements are often overlooked as architectures are often adopted based on what is known or legacy practices (i.e., "This is how we have always run our ESPs.") To illustrate how the functional requirements can be achieved, a wide range of completion architectures were compared and evaluated against the "functional check list" and the review contains references of where these completions have been successfully installed. One of the findings was that, all too often, the completion architecture does not provide a method for circulating the well without losses to the reservoir, which is an important consideration for maintaining flow assurance. Of course, the perfect ESP completion architecture does not exist. However, this review of requirements and completion architectures provides the practicing completion engineer with a methodology for developing the inevitable engineering compromise between cost, complexity, and value based on documented functionality.
Successful Geosteering And ICD Completion In Flank Areas Of Mauddud Carbonate, North Kuwait: Lessons Learned And Experiences Gained
Authors: Nair S. R. , Chetri H. B. , Al-Ajmi H. Z.
Published: December 2013

The Mauddud carbonate, a ‘Major' reservoir in Sabiriyah field, North Kuwait, is about 400 feet thick dominated by carbonates deposited in a ramp environment. The reservoir has ten sub-zones named alphabetically from top MaA to MaJ. Current drilling campaign is being executed on fast track exclusively using Non-Conventional Wells (NCW) in order to achieve production targets.

The planned NCWs are located in flank areas to have optimum exploitation of flank potential. ‘MaB' is target zone as water flood development of the reservoir, as a whole, calls for enhancing the production from MaB and provide the pressure support via water injection at the MAE (Bottom-up approach). The laterals planned are in the range of three to five thousand feet.

Several subsurface challenges were dealt with during design and execution phases. The trajectories are planned with strike parallel azimuths to have minimum inclination changes in lateral sections. The objective is to enable trouble-free operation during ICD deployment. This task was extremely difficult due to local dip changes and variations of actual strike directions. Structure models were constantly updated with real time data and gradual azimuthal shifts were made to achieve this objective. The wellbore must remain in "sweet spot?? throughout. Geological models were used to design trajectories accordingly. This mission was arduous due to sparse well density thereby reducing reliance on models. Presence of sub-seismic faults could place wellbore in undesired stratigraphic positions. Such occurrences were perceived and predicted as best as possible based on regional structural picture and calculated steps were taken. In the eventuality of wellbore hitting unexpected faults, gradual azimuthal-inclination changes were made to correct well paths.

With all these efforts and strategies, the operations team was able to successfully execute drilling and completion of Sabiriyah Mauddud Horizontal wells. The paper is aimed at sharing the success story achieved in North Kuwait.
Selection of Commercial Kinetic Hydrate Inhibitors Using a New Crystal Growth Inhibition Approach Highlighting Major Differences Between Them
Authors: Glénat P. , Bourg P. , Bousqué M.-L.
Published: December 2013

Kinetic Hydrate Inhibitors (KHIs) are one of the two types of Low Dose Hydrate Inhibitors (LDHIs) which are more and more used for gas hydrate control in the oil and gas industry, offering significant CAPEX advantages over traditional thermodynamic inhibitors (e.g. methanol, glycols). As KHIs are traditionally considered "nucleation inhibitors", their lab evaluation is generally undertaken by measurement of an "induction" or "hold" time before hydrates start effectively to form. However, as nucleation is stochastic by nature, obtaining repeatable/transferrable data is often highly problematic and time-consuming, making robust evaluation difficult. A new crystal growth inhibition (CGI) approach has been recently published which showed that KHIs induce a number of highly repeatable, well-defined hydrate crystal growth inhibition regions as a function of subcooling, ranging from "complete" inhibition, through severely to moderately reduced growth rates, ultimately to final rapid/catastrophic growth as subcooling increases. Delineation of these regions provides much more reliable and rapid means to evaluate the relative performance of KHIs under simulated worst case scenario conditions. Nine commercial KHIs have been provided by vendors for one gas/condensate field development in the Middle-East. The screening of these nine KHIs with the CGI method highlighted great variations in their ability to inhibit crystal growth. Furthermore, the ability of some KHIs to completely or severely inhibit hydrate growth even when modest fractions of hydrate (>1% of converted water) are present strongly demonstrates that commercial KHIs can act very differently and that this test method allows to identify "robust" additives compatible with real operating conditions.
New Technologies in Fracturing for Shale Gas Wells are Addressing Environmental Issues
Authors: Nakhwa Amit D. , Huggins Ken , Sweatman Ronald
Published: December 2013

This paper discusses how applied science, historically safe operations, advancements in technology and standard processes are helping to address and reduce environmental issues (EI) for hydraulic fracturing in shale gas wells. The technologies presented include equipment footprints allowing for a reduced risk for environmental effects, 3D fracture mapping, microseismic fracture mapping, "green" fracturing fluids, bacteria control through UV light technology and an improved method of water recycling. This combination of scientifically-derived technologies and best practices (a.k.a standards) is assisting in lowering the risk for EI and addressing misconceptions about hydraulic fracturing.

To further address these environmental issues, members of Oil & Gas (O&G) industry associations, including the American Petroleum Institute (API), Society of Petroleum Engineers (SPE), International Association of Drilling Contractors (IADC) and the International Association of Oil & Gas Producers (OGP) based in London and Brussels, continue to develop sound science and field-proven best practices in the form of industry standards, such as those referenced in this paper.

Technical publications by O&G service companies have provided numerous case histories highlighting these applicable technologies. These presented technologies and practices have helped to demonstrate the positive impacts for shale gas development projects.
New Insights into Surfactant System Designs to Increase Hydrocarbon Production
Authors: Sherbeny Wael El , Bakr Dalia , Quintero Lirio , Jones Tom , Anwar Mohamed , Moussa Doaa
Published: December 2013

Drilling and completing reservoirs without inducing measureable skin damage is rare. Frequently, drilling fluids impact a reservoir’s flow potential while drilling as the rock matrix is invaded by solids and chemicals designed to enhance drilling performance. Drilling fluid can also cause formation damage if they are not properly removed during the displacement phase. These solids can migrate to the perforating zone and cause damage. Completion fluid designs governed by density for well control also often contribute to skin damage. Hydrocarbon flow may be impeded by damage caused by residual drilling debris or incompatible completion and workover fluids, in-situ emulsions, water block, organic deposition, or oily residue.

Specialized surfactant systems have been developed to remediate near-wellbore damage caused by drilling and completion fluids, and damage induced by failed remediation attempts. The properties of these treatment systems include their ability to solubilize oil and, due to a significant reduction in interfacial tension between the organic and aqueous phases, effectively diffuse through the damaged zone to free up flow-resistant obstructions. The inherent properties of these systems make them ideal for removing induced formation damage as well as an excellent option for displacing synthetic or oil-based mud (S/OBM) from casing prior to the completion phase. In open-hole (OH) completions, specialized surfactant designs have proven very effective in removing S/OBM filter cake damage. In cased-hole (CH) completions, they have demonstrated a high degree of efficiency to clean damaged perforations.

This paper presents a technical overview of surfactant systems for OH and CH remediation operations. The testing to qualify these fluids for the removal of damage and field results are presented that show the efficacy of these specialized surfactant systems to remove damage caused by OBM filter cakes and other oily debris to improve hydrocarbon recovery while addressing the operational challenges associated with these jobs.
Challenge and Successful Application for Scale Removal Gemsa Oil Field, Egypt: Field Study
Authors: Elmorsey S. A.
Published: December 2013

Water flooding is the hinge pin for Gemsa Oil Field. Water injection is supplied from shallow water supply wells. Compatibility tests had indicated probable deposition of calcium sulphate scale on surface and subsurface production equipment. Calcium sulphate scale has been recognized to be a major operational problem. The bad consequences of scale formation comprised the contribution to flow restriction thus resulting in oil and gas production decrease. The nature of calcium sulphate scale is very hard and can't be dissolved with known dissolver. Sister companies that has similar problem were always going to the mechanical remover options.

Extensive lab and field work was conducted to determine the suitable chemicals to dissolve calcium sulphate scale. This paper describes the development and field application of chemical treatment to remove scale in an offshore 8" production line in Gemsa oil field. Continuous precipitation of calcium sulphate scale caused partial plugging of the pipeline. This partial plugging created a back pressure on production wells which decreased the productivity. The field production has been decreased to almost one tenth of the normal field production level(1).

A thorough investigation was conducted to identify the composition and location of the scale, in order to recommend a suitable chemical to remove the scale, and to assess the effectiveness of the treatment method in the field.

Based on extensive lab studies, SAG-01 was tested and applied in production line to remove the scale efficiently, the program was designed taking into consideration the nature of the scale.

The treatment program included three - staged process: The use of an organic solventThe main treatment (SAG-01).The post flush stage (injection water),

The job results were outstanding, where as 1-Production increased by about 2,000 BOPD2-Launcher pressure dropped by about 350 psi.3-Decrease the back pressure on our producing wells.4-Additional producing wells into production. Efficient cost /Bbl.
Hydrocarbon Mobility Steering for Optimum Placement of a Power Water Injector above Tar Mats - A Case Study from a Light Oil Carbonate Reservoir in the Middle East
Authors: Saint Craig , Glowig Thomas , Swain Ashis S , Al Khaldi Nasser A. , Al Otaibi Mohd. H. , Al Ghareeb Abdul aziz , Al Bader Ahmad Bader
Published: December 2013

Tar mats are encountered in many Middle East carbonate reservoirs including the Kingdom of Saudi Arabia.

Tar is considered to be very heavy crude that does not flow or has very limited flow capacity at standard reservoir conditions. In some cases it is found above the aquifer and below a light oil layer. As tar is practically immobile at reservoir conditions it acts as a flow barrier between water and light oil, causing significant challenges for reservoir development. In such cases water injectors work most efficiently when placed horizontally just above the tar mat to maintain pressure support during production.

One challenge when drilling for these water injectors is to optimize their position above the tar layer yet as close as possible to the tar to maximize sweep efficiency. A further complication for their placement is the uncertain lateral distribution of the tar in terms of true vertical depth (TVD). The top of the tar layer is often an undulating lateral surface with varying depths.

Positioning the well a "safe" distance from the tar is not a good solution as it might leave behind a significant volume of producible oil, ultimately lowering oil recovery.

A real-time tar detection method is needed while drilling to quickly respond and modify the wells trajectory if tar is encountered.

The low mobility caused by tar can be detected with a formation pressure while drilling (FPWD) tester. A nuclear magnetic resonance (NMR) tool provides oil viscosity estimation and additional tar-related properties. In combination with a conventional logging string, tar can be positively detected while drilling.

This case study from a carbonate field in KSA shows the successful placement of a 6.25-in. horizontal well using a logging-while-drilling (LWD) NMR-device and an LWD formation pressure tester to detect tar in combination with conventional resistivity, density and neutron (triple-combo) LWD logs.
Restoring Integrity of the Platform by Abandoning Gas Producer Well Suffering From Integrity Problems
Authors: Mohamed Shanof , Al-Hosani Ibrahim , Al Neaimi Ahmed K. , El Sayed Mohamed , Abdelsalam Mohamed
Published: December 2013

This paper presents the innovative planning methods and highlights of the operations completed for the abandonment of a gas producer well suffering from integrity problems thereby restoring the integrity of the platform and putting the other wells on production. The integrity problems were oil/gas bubbles seen on the sea bed around the conductor pipe and high sustained pressures in the outer cemented annuli of 18 5/8" × 13 3/8" and 13 3/8" × 9 5/8". The entire tower/ platform was considered highly dangerous and unsafe under these conditions and the tower was risk ranked No. 1. Consequently, the wells on this platform were secured in January 2001.

A task force was formed to investigate the problem and propose solution. The team proposed to permanently abandon the gas well to restore the integrity of the tower. The possible source of leak was identified by monitoring the annuli pressures, measuring fluid samples, running noise and temperature logs and leak rate tests. After analyzing all the problems, the team agreed to isolate the source of leaks by remedial squeeze jobs through selected perforated intervals with additional barriers like bridge plug. International standards were adopted in planning for the abandonment of this well.

There were several challenges involved in the abandonment of the well like identifying the possible leak sources, perforation against 4 casings, adopting international standards for abandonment, choosing the type of barriers, cement type, ensuring the integrity of the barriers etc. Finally, the team through continuous effort and hardwork overcame these challenges, produced a robust plan and executed the operation safely in cost effective manner.

The paper serves as a good reference for the abandonment of gas wells following international standards and other areas include perforation against four casings.
Improved Dehydration and Desalting of Mature Crude Oil Fields
Authors: Sellman Erik , Sams Gary , Mandewalkar S. Pavan
Published: December 2013

Mature crude oil fields most often contain higher water cuts and higher content of fines. The combination of a large population of water droplets and fines form very stable crude oil emulsions that are difficult to break.

The higher water cuts provide higher crude oil emulsion viscosity because of the larger population of small water droplets, often leading to a need for higher operating temperatures, frequent production upsets and high demulsifier dosage.

Another challenge is arcing between electrodes as a result of the higher water cuts. Typically older crude oil dehydration and desalting treaters use AC type electrostatic technology, which are less effective in treating crude oils with higher water cuts.

The use of combined AC / DC electrostatic technology provides a two prong approach where bulk water is removed in a weaker AC field and remaining smaller water droplets are removed in a stronger DC field. Further improvements to the AC/DC treaters include use of composite electrode plates, modulated electrostatic fields as well as improved fluid distribution inside the treaters.

AC / DC treaters provide an attractive opportunity for retrofitting existing AC treaters in mature fields and make the treaters more suitable for dehydrating the crude oil emulsions from these fields.

This paper describes new enhanced electrostatic dehydration technologies suitable for treating higher water cut crudes from mature fields, efficient test methods for optimized usage of production chemicals and selection of electrostatic technologies, including case studies.
Asset Integrity Management System Implementation
Authors: Rezaei Cyrus , Abbas Ahmed A.
Published: December 2013

KOC commenced preparation of Integrity Management (IM) System Standard & Guidelines in 2003. The IM system implementation sits under HSE umbrella at present and compliments the existing HSE management system policy and procedures. KOC operations assets include North Kuwait (NK), WK, S&EK, Gas Operations/Management and E&PD (Exploration & Petroleum Development). Major Projects are also managed by TSD (Technical Service Directorate) & Controlling Teams including Inspection & Corrosion. Initially, a set of six critical areas for IM implementation was agreed with the operating assets and KPIs (key performance indicators) were defined accordingly. These comprised of chemical management system, safety critical equipment, emergency shutdown system testing, fire & gas detection system, replacement of pipelines temporary clamps with permanent ones and procedure for control & monitoring of safety overrides equipment. Previous integrity related incidents were analysed to identify the immediate and root causes and a basket of IM KPIs was prepared accordingly. The analysis also included the minor incidents, near misses, unsafe acts & conditions and lessons learned from inside and other Oil & Gas companies. Each asset selected a number of KPIs as applicable to the nature of their operations and prepared a 3 years rolling plan accordingly. Each asset monitors implementation of their selected KPIs and quarterly performance reports are compiled in an auditable manner. Achieved KPI targets are sustained for continuous improvement cycle & new KPIs are introduced into the IM basket as/when identified. IM system has now focused on PSM (process safety management) related aspects and incident prevention. Although the HSE management system has been focused on personal safety, IM/PSM system is aiming to enhance the process safety and prevent PSM related incidents. This provides a more holistic approach to enhance personnel responsibilities, competency development, safety critical equipment identification & respective PM (preventive maintenance) plans and incorporation of Inherently Safer Design (ISD) principles in project concepts to prevent loss of containment.
Design of SOS-FR (Steam-Over-Solvent Injection in Fractured Reservoirs) Method for Heavy-Oil Recovery Using Hybrid Optimization Framework
Authors: Al-Gosayir M. , Babadagli T. , Leung J. , Al-Bahlani A. M.
Published: December 2013

In order to reach the ultimate heavy oil and bitumen recovery with minimal cost, efficient and optimized design for recovery processes operation strategies is necessary. Despite the amount of the heavy oil and bitumen reserves around the world, the production is limited due to the production development difficulties such as high cost, complex processes, and environmental concerns. Many design and performance evaluation studies published in the literature combine numerical simulation with graphical or analytical techniques; however, only few design elements are handled due to the difficulties of handling large number of factors. Due to the high computation requirements, limited efforts that integrated the simulation exercise with global optimization algorithms to handle more design elements.

In this paper, a hybrid global optimization framework is used to optimize the design of a new process called Steam-Over-Solvent in Fractured Reservoirs (SOS-FR) proposed by Al-Bahlani and Babadagli (2008, 2009a-b, 2011a-b). The hybrid framework integrates genetic algorithm with orthogonal arrays and response surface proxies for better convergence behavior and higher computational efficiency. The SOS-FR technique consists of a heating phase using steam injection, subsequent solvent injection, and low temperature steam injection for solvent retrieval and additional oil recovery. Solvent injection can be continuous or cyclic where the solvent is injected, soaked, and then fluids are produced. This paper studies both scenarios over single and multiple matrix field scaled reservoirs by adjusting the injections’ durations and rates. As a result, about 30 design elements for four base benchmark models are optimized, and the profit and efficiency is doubled comparing with the benchmark models using optimal injection scheme suggested by our optimization framework.
Challenges in Testing and Completion of Highly Sour HPHT Reservoir in The State of Kuwait
Authors: Al-Salali Yousef , Al-Bader Haifa , Duggirala Vidya Sagar , Manimaran A. , Packirisamy S. , Al-Ibrahim Abdullah , Rajkhowa Anupam
Published: December 2013

Testing and completing deep reservoir in the state of Kuwait is challenging due to high contrast in formation pressure over the 4,000 feet section (13,500’ to 17,500’). Recently, a new structure located in the North-Western part of Kuwait area was drilled and tested with deep drilling rig. Formations in this deep structure have very low porosity and permeability with naturally fractured reservoir. During short term testing, wells produced oil and gas with unexpectedly very high H2S(20%–35%), the highest H2S content in any reservoir so far discovered in the state of Kuwait. Since the reservoir was rated as HPHT and sour, it was a challenging experience to test all the wells safely and successfully. Unfavorable conditions such as high pressure, high temperature, high H2S and CO2 content require special equipment, tools and treatment to test and complete exploratory wells.

The targeted formations were perforated using deep penetration TCP guns, stimulated with emulsified/retarded acid, tested with Drill Stem Testing(DST) tools and sampling was done. Meticulous planning and testing strategies could overcome all challenges and high sour reservoir was successfully tested safely without any incident. The wells were flowed only for short period due to high sour nature of the reservoir fluid and safety reasons. However, data collected during short term testing helped in understanding production capability, fluid and reservoir characteristics which is vital for delineation/development of the new field. Methods developed, data obtained and expertise gained in testing and completing high sour wells will be useful for the future development of sour gas reservoir.

Aim of this paper is to describe the actual challenges encountered and lessons learned during testing and completion of hostile environment wells. This paper also aim to present techniques and approach adopted to address the operational risk and HSE issues during perforation, Coiled Tubing, stimulation, well testing and sampling operations.