bluuebunny/crossref_metadata_2025 huggingface dataset:
Effective Use of Resistivity Behind Casing to Improve Oil Recovery From a Brown Oil Field: A Case Study from the Western Desert, Egypt
Authors: Badr Abdallah B. , Mahgoub I.. , Dutta D. J. , Van. Steen M..
Published: February 2010

Enhancement of oil recovery and reduction in water-cut in a matured field requires precise time lapse saturation monitoring. Behind casing resistivity, an important member of the comprehensive analysis behind casing services suite, provides required answer by acquiring deep resistivity information through casing and subsequent formation evaluation. A time lapse saturation figure could be generated immediately after the acquisition which is extremely instrumental to take immediate decision. The technology is well known in the industry and already proved beneficial in many occasions. In favorable conditions, this is the most effective methods available to date for saturation monitoring as being the deepest through casing measurement in terms of radial investigation.

The case study presented in the paper describes a successful water shutoff operation and enhance oil recovery from the Bahariya formation in the western desert, Egypt. The well was drilled in early 2006 followed by logging and testing and was put on production immediately after completion. Over about one and half year, the oil rate decreased by 70% with 86% water cut.This significant fall in oil output with sharp early water break through, a common phenomenon in this mature field required a proper shutoff operation. The present example discusses in detail the reason in choosing resistivity behind casing acquisition and time lapse formation evaluation to monitor present saturation profile. Comparison between original and present water saturation level immediately detects the depletion zones and the degree of depletion across perforated intervals indicates the interval contributes most of the produced water. In the present example the cased-hole resistivity acquisition shows departure (lowering) of resistivity values against some perforated intervals. The zones were isolated after identification of the intervals that shows considerable lower in values. This is considered as an indication of rise in oil-water-contact or lengthening of transition zone. In the present case, the remedial measures for water shut-off operation based on time lapse evaluation have enhanced oil recovery from 540 Barrel to 2250

Barrel oil per day with significant reduction in water cut from 86% to 1%.

The results were encouraging enough for the operator to reinvestigate the production performance and identify wells where this technique could be meaningfully utilized. The current analysis and workflow offers a fairly good understanding about the reservoir's production scenario, monitoring and future actions for enhanced recovery.
Application of a New Computer Aided History Matching Approach - A Successful Case Study
Authors: Gherryo Yousef S. , Shatwan Mohamed B. , Abrahem Fathe A. , Heinemann Zoltán E. , Mittermeir Georg M.
Published: February 2010

The reservoir, located in the Sirte Basin, Libya was discovered in the early 1960s. Since then, more than 65 wells have been drilled. By the end of the year 2008, more than 160 MMstb undersatured oil have been produced from the Upper Cretaceous. Water cut has risen to 65% and average reservoir pressure is still 1000 psi above bubble point. The individual well production history is highly influenced by water coning.

The field is geologically complex; heterogeneous, contains numerous large and smaller normal faults sometimes associated with fractures, leading to local permeability enhancements. Average gross thickness is about 300 ft. Recovery is mainly (80%) by the strong edge water influx and by expansion (20%).

The objective of the History Match (HM) was to accurately determine the distribution of the reminder movable oil, in order to enable reliable performance predictions of existing and future wells. To meet this goal, the total amount of produced fluids on a well-by-well basis as well as the average local pressure must be matched within close limits.

Conventional HM techniques failed due to the complex geology and production history. Especially the highly variable water cut could not be matched satisfyingly. For this reason, a new HM method and workflow, called Target Pressure and Phase Method (TPPM), was applied. TPPM ensures, that the calculated average reservoir pressure and the calculated amount of produced liquids match the corresponding measured values at every point in time. This is achieved by regulation of water influx from artificial boundaries and automatic distribution of the inflow along the well trajectories. Thus, the engineer can immediately concentrate on matching the well-by-well performance leading to a considerable reduction in project duration. Additionally, TPPM gave excellent results in HM. Thus reliable future field operation scenarios can be designed and calculated. The presented workflow and method is generally applicable, especially for reservoirs under strong water influx.
Sweet Success in Sour Coring
Authors: Briner Andreas , Azzouni Abdul-Hameed , Chitnis Rajendra , Vyas Vishal
Published: February 2010

The South Rub Al-Khali Company Limited (SRAK) is a Joint Venture between Shell and Saudi Aramco and is engaged in exploring in the Rub Al-Khali Basin of the Kingdom of Saudi Arabia. The licence area contains significant quantities of ultrasour gas in the Jurassic Arab Formation reservoir. Acquiring accurate subsurface data forms a key objective for SRAK in its ongoing exploration drilling campaign in this remote and challenging desert environment.

Health, Safety and Environment (HSE) is at the forefront of SRAK's operations. This paper presents how extensive pre-job planning and proper execution of new procedures led to the safe and successful coring of the hydrogen sulphide (H2S) rich Arab Formation in the eastern Rub Al-Khali of the Kingdom of Saudi Arabia.

In SRAK's most recently completed well, five continuous cores, with a total length exceeding 350 ft were successfully cut, with a high recovery factor of 99%, covering the Mesozoic Arab C and D members of the Arab Formation. These gas-bearing reservoirs were known to be very rich in H2S and carbon dioxide (CO2) posing environmental and technical challenges for data gathering. Through strict adherence to extensive procedures and training, the operations were successful and were conducted safely and efficiently.

The operations were planned well in advance with a dedicated workshop incorporating the well engineering group, subsurface teams and the coring and core analysis companies. Detailed step-by-step discussions of the coring workflow identified gaps in existing core acquisition procedures. The coring contractor, based on the expected high levels of H2S, updated existing HSE coring procedures. Specific HSE procedures that covered the interface between the different parties were set-up and communicated. Mandatory H2S-specific training was extended to cover all staff, from logistics, operations team to the core analysis personnel.

In addition to the HSE aspects, the mud system and core barrel vibrations were closely monitored to guarantee good core recovery with a maximum of H2S scavenged. Special attention was also given to the cores after recovery to ensure no poisonous gas is released in an uncontrolled manner.

The data obtained from the Arab Formation cores has been a vital component in establishing SRAK's understanding of the geology, hydrocarbon-fill history and in-place volumes of the company portfolio.

The intention of this paper is to share the proven guidelines for coring, core handling and core processing, of rocks from H2S-bearing formations, for the benefit of other operators of sour gas fields.
Fast-Track Maturation and Development of the Al Fadl & Al Qadr Fields, Two New Discoveries, NEAG East, Western Desert, Egypt
Authors: Bakr Ahmed , Le Varlet Xavier , Postuma Willem
Published: February 2010

Al Fadl & Al Qadr fields are located in the eastern part of the Abu-El-Gharadig Basin (Western Desert, Egypt). The exploratory wells Al Fadl -1 & Al Qadr -1 were drilled late 2007, encountered under saturated oil in the Bahariya Formation (Cretaceous). The development lease was granted in January 2008 after the successful testing of the wells. Production started in April 2008. These discoveries offered an attractive opportunity to increase Bapetco's oil production. Due to its location away from the existing Bapetco facilities, Early Production Facilities were installed to enable production to start just after the development lease was granted. The development required an integrated and x-asset planning approach to accelerate its development and maximize hydrocarbon production without compromising other development. The main strategy was to fast-track maturation and appraisal/development opportunities in the area. The main aim was to expand Bapetco's operations and achieve early production, and prepare for the secondary recovery (water flood scheme). The Petroleum Engineering studies consisted in the construction of comprehensive 3D models of the marginal marine reservoir sequences capturing key uncertainties. The static models were exported to dynamic simulators. Geological, petrophysical and reservoir engineering data were integrated to create realizations reflecting extreme scenarios for reservoir parameters such as reservoir architecture, structure and fluid contacts in an attempt to define the in place hydrocarbon volume range, the static connectivity and to test the robustness of the development concepts. Dynamic models were used to provide forecasts for proposed realizations. Very successful multidisciplinary integrated study work resulted in fast track maturation of FDP and delivery of 27 well proposals within 6 months. The development scenario selected consists of an inverted 5 spot pattern (spacing between well producers of 600m, fracced wells, ESP completion). Currently the fields are producing through the EPF system while development drilling is delivering 2 producers a month. Water injection is planned to start in the Q1 of 2010.
Lower Safa Sedimentological Study, New Insights in the Reservoir Quality Distribution of the Obaiyed Field, Western Desert, Egypt
Authors: Saad Ahmed , de Groot Michiel
Published: February 2010

The Obaiyed gas/condensate field is located the Western Desert 50Km South of Marsa Matrouh. The Jurassic Lower Safa member (the reservoir bearing unit) consists of massive sandstones, which after deposition were subject to extensive deformation. A wide range of reservoir qualities is found in the field, with permeabilities ranging from tight (sub 0.1 mD) to high (up to 600 mD). Even after drilling 11exploration/appraisal and 30 development wells in the Obaiyed area, there are still significant subsurface uncertainties in the reservoir quality and extension, as shown by the 20% failure rate of the development wells. In order to improve our understanding of the Lower Safa reservoir, EREX Egypt was asked to make core descriptions for 15 wells in the Obaiyed field. They described 824m out of 1300 m total core length, to determine the depositional model of the Lower Safa. The conclusion of the study was that the main reservoir can be described as an estuarine deposit, with strong tidal influences in the earlier sequences, that evolved vertically into a wave-dominated deposit. The sedimentological study resulted in a simplified facies scheme that was used in Petrel to generate a 3D model for history matching. Unfortunately, it proved impossible to make a core-log correlation that could guarantee the successful production of new development wells. It was decided to take the reservoir quality uncertainty as a given and develop a completion strategy that would enable BAPETCO to produce the wells in any case. Therefore BAPETCO is planning a staged massive frac strategy in the coming years in parallel to the infill drilling campaign to maintain our production plateau and increase the ultimate recovery from the field.
Investigation of Effect of Fracturing Fluid on After-Closure Analysis in Gas Reservoirs
Authors: Soliman M. Y. , Miranda Carlos , Wang Hong (Max) , Thornton Kim
Published: February 2010

Published techniques for analysis of fracture-after-closure data usually assume single-phase flow. These procedures generally rely on the techniques developed for the analysis of buildup tests. Applying the buildup techniques implies that the injected fluid and reservoir fluid have approximately the same properties. This assumption is generally incorrect in case of MiniFrac tests where the injected fluid may be very different from the reservoir fluids. This situation is at an extreme when the MiniFrac test is conducted on a gas reservoir and the injected fluid may be a relatively high viscosity gelled fluid.

This paper briefly reviews the various available techniques for after-closure analysis discussing the strengths and weaknesses of each. Using a numerical simulator, MiniFrac tests are simulated and analyzed for both oil and gas reservoir cases where an aqueous phase is injected as a fracturing fluid. Analyses of the numerically-simulated falloff data are presented. Guidelines for the analysis of such data have been developed and presented.

Field data are also presented. In one case, breakdown, step-rate, and fluid efficiency tests (FET) were performed on a tight gas formation and the data were analyzed. The results of using these various techniques are presented. The consistency of results validates conclusions achieved using the numerically simulated data. In another field case, a test that was performed during drilling was analyzed.
Detecting Thin Lens-Shape Features in Kharita Member in Aghar SW Field Using Multi-Azimuthal Offset VSP, Western Desert, Egypt
Authors: Abdel-Hafez Tarek , El-Makarem Abo , Hosny Mohamed , Ahmad Parvez , Hosny Shady
Published: February 2010

Complex near-surface conditions and subsurface geology pose problems for seismic imaging in Western Desert and require new survey design approaches, sensor technology and processing techniques. In Aghar SW Field in West Razzak Development Lease (Western Desert) the main reservoir is the Bahariya Formation but hydrocarbons were found in some wells also in the Kharita Member.

This paper presents a case study from Aghar SW Field where conventional 3D surface seismic could not resolve the hydrocarbon bearing sandstone layer intercalated within shale in the Kharita Member and the decision on planning an additional development well was very difficult.

Borehole seismic was considered as a viable solution to enhance the seismic resolution and map the extension of a sub-seismic hydrocarbon bearing layer. A cost effective multi-azimuthal VSP survey was designed in Offset VSP configuration placing seismic energy source at different source offsets and azimuths around Aghar SW 5 ST Well.

Data were acquired using 3-component multi-shuttle Versatile Seismic Imager tool as downhole geophone and vibroseis as seismic energy source. Multi-component processing was carried out in Walkaway VSP configuration combining the data optimally. VSP high resolution images resolved successfully the thin lenticular productive sandstone layer and the location for Aghar SW 6 Well was chosen accordingly.
Special Core Analysis for Integrated Static & Dynamic Reservoir Modeling Bapetco NEAG1 Field
Authors: ElBelisy Mohamed , Bakr Ahmed , Ahmed Ismail , Albaaj Elena , Wahdan Maamoun
Published: February 2010

NEAG1 is one of Bapetco fields located in the eastern part of the Western Desert, close to Qarun field. Special Core analysis has been used in an integrated way to optimize parameters used in Static and Dynamic reservoir models. The methodology of selecting the adequate core plugs was an integrated work of PP, PG and RE engineers to ensure optimal selection of samples representative for the reservoir. Routine Core analysis and core photos, logs, SEM were used in the selection procedures.

The results are being integrated into the Static and Dynamic model and they show an improved prediction of reservoir properties.
Rheological and Core Flood Studies of Gelled and In-Situ Gelled Acids
Authors: Gomaa A. M. , Nasr-El-Din H. A.
Published: February 2010

Polymer-based acids, which have been used in the field for decades for acid diversion, were examined extensively through the literature. Recent lab work indicated that these acids could cause damage under certain conditions, while field data gave positive and negative results. The behavior of these acids is not fully understood. Permeability enhancement, radius of wormholes, diversion efficiency and damage mechanisms are determined in part by the rheological properties of these acids. Rheology of In-situ gelled acids exhibit strong viscoelastic properties at pH greater than 2. Therefore, the objectives of this study are to determine the elastic and viscous properties of these acids, how these properties change as the acid reacts with carbonate formations, and what their effect on acid diversions.

Experimental studies were conducted to measure the rheological properties for polymer-based acids using oscillatory rheometer. To the best of our knowledge, this is the first time that the viscoelastic properties were measured for these acids. Measuring the elastic modulus (G') and viscous modulus (G") were done using two tests: Dynamic sweep tests, which were used to define the shear rate dependent response; Creep tests, which were used to define the time depended response.

The behavior of gelled acids was independent of pH while the behavior of in-situ gelled acids varied with pH. Gelled and live in-situ gelled acids had weak viscoelastic properties while partially neutralized (pH 3.2) in-situ gelled acid had strong viscoelastic properties. Polymer filter-cake formed in case of gelled acid injection while in-situ gelled acids didn't form any polymer filter-cake. This is because of the in-situ gelled acid formed a thin layer of gel that minimize the leak-off which prevent the build of polymer filter-cake. The strong viscoelastic properties determine the effectiveness of diversion. As elastic properties increases, the formed gel will sustain around the wormhole and plug it. This will force the next acid stage to penetrate the weakest point and change its direction. For gelled acid, the inlet face washout and the polymer filter-cake reduced the core permeability to zero by plugged the core holder inlet during the water flow back. However after removing the plugging effect, a permeability enhancement was much higher than in-situ gelled acids. The wormhole obtained in case of gelled acid was nearly linear and thinner than the wormhole created by in-situ gelled acid. The results obtained can be used to better design matrix acid treatments when polymer-based acids are used in the field.
Research of Gas Separator with Disperser Influence of ESP Work and Increase of Well Operation Efficiency by the Use of ESP
Authors: Mokhov Mikhail
Published: February 2010

In recent years there is a tendency of standing increase of ESP share in performance stock of oil recover companies. At the same time there is an increase of oil production from drowned wells observed in consequence of universal application of water flooding and depletion of most of the large deposits. The average water cut of recovered products at pump operation is at present from 80 to 85 per cent. As is known, one of the complicating factors of steady operation of ESP is free gas inflow into the pump. For the protection of ESP against free gas harmful effect on the oil-fields, gas separators are widely used because they allow to separate some of the gas into the annular space. When water cut increases, the quantity of free gas in the flow stream drops, and it becomes possible to apply a disperser, which is required for the generation of fine liquid-gas mixture which, on reaching the inlet of ESP, decreases free gas effect on the pump operation. The application of dispersers is also well grounded for zero water-cut oil fields with moderate-size gas oil ratio.

Frequently, in order to protect ESP from an adverse gas effect, gas separators are used, which drop part of precipitated gas into the annular space. A considerable part of associated gas in the annular space under certain conditions can lead to the formation of hydrate and paraffin-hydrate blocks which stop up the annular space and create conditions for both the separator and the ESP work breakdown, down to the pump starvation. It is noteworthy that the gas dropped in the annular space doesn't do raising fluid operation. This work is done by the pump, which leads to power consumption and production cost increase, as well as error-free running time decrease.
Planning the Subsurface Modeling Tool for the Full Field Life Cycle and Influences of Multi-Disciplinary Integration on Static Modeling: Examples from the Sitra Field, Egyptian Western Desert
Authors: Abd El Rahman Hassan , Wahdan Maamoun , Le Varlet Xavier , Toukhy Ahmed
Published: February 2010

This paper demonstrates how a holistic modeling approach and multidisciplinary integration were used to plan the longer-term development of a recent, promising discovery.

The Sitra field was discovered in 1983. Three subsequent appraisal wells discovered additional reservoirs. The wells also demonstrated that sand prediction and lateral connectivity would be a dominant challenge to field development..

A joint SENV/BAPETCO/EPTS multi-disciplinary project was initiated to help plan the further appraisal and development of the field. The static model was to become the backbone of the subsurface work. The model had to be useable for both immediate and longer term field development planning and had to fulfill the requirements of various departments.

Well engineering safety guidelines required the conservative 3D rendition of the main bounding fault. Petroleum engineering required the most realistic structural model for the main area of the field and boundary fault.

In the main reservoir, multi-disciplinary integration played a key role in the construction of the geological model. The background was provided by a recent regional study. AVO inversion provided results that could only be used qualitatively, but a seismic Stratigraphic interpretation integrated with sequence Stratigraphic well correlation and sedimentlogical core description did indicated the potential presence Tidal Channel/Bar system which fit in the context of all other subsurface data. The resulting conceptual model is of an Delta/Submarine depositional system in which high quality channel sands are concentrated in two NNE-trending systems. The 3D Facies model was constructed accordingly.

This static model was fully history matched and used to forecast alternative development scenarios for this Oil/Gas reservoir, providing a strong basis for future reserves reassessments.

Integration across disciplines, organizations and locations was critical in project delivery. The common 3D Grid helped in sharing information between different teams and reinforced cooperation. Remote working tools were important in the transfer, handover and sharing of information and models.
Developing National Talent to Meet Future Production Opportunities in Egypt
Authors: Youssef Ahmed Alaa , El-Refai Hashem , El-Tobgy Sherin , Beare David , van den Broek Ton
Published: February 2010

The Badr El-Din Petroleum Company ("Bapetco") has always invested in developing the competency of its field and well operations staff with significant success achieved over the last 25 years of operations. Growing Bapetco's and Egypt's National talent resource is essential to continuously improve operational excellence in all activities and to implement advanced technologies to sustain and increase production. Historically, competency development was supported by a combination of on-the-job training and formal classroom training programmes. These competency development methods have been augmented over recent years by blended learning techniques and formal competency assessment to recognise and reward achievement of levels of skills and experience within a formal mentoring and accreditation framework. This paper details the remarkable progress made so far and Bapetco's approach to achieving a sustainable and internationally recognised competency development programme for well and field operational personnel in Egypt, and beyond.

The paper describes what has so far been achieved and what initiatives are underway to ensure that Bapetco's and Egypt's current and future competency requirements in the well and field operations domain are met.

Results/Conclusions - The Bapetco Wells section, i.e. Well Engineering (WE) and Completions & Well Interventions (C&WI) discipline has always been supported by internationally recognised accredited competency development programme (Shell's Drilling Round I and II). This has supported Bapetco business aims and led to a doubling of the number of drilling rigs supervised by qualified National Drilling Supervisors, and recognition of Bapetco for its international accreditation of its first Well Services Supervisors. This has also benefitted the Egyptian oil and gas sector by supplying the Well Engineering and Well Services discipline with a steady stream of qualified engineers. Graduate engineers benefit greatly from progressive competency development, thorough blended learning, and professional accreditation to attain progressive competency profiles. The benefits of this approach have been identified and the drive is to continue to extend the development and accreditation programmes across the Wellservices and Field Operations disciplines to make sure that National talent is groomed professionally to take on the leadership of Bapetco's future oil and gas developments, and make an important contribution to the wider Egyptian oil and gas sector.
Using Wellbore Stability Analysis to Improve Drilling Performance: Case Study from the Western Desert, Egypt
Authors: Van Steene Marie , Povstyanova Madgalena , Al-Attar Haitham , El Gheit Diaa Abu , Abutaleb Moamen , Lantz Jim , Abdel Kareem Salah
Published: February 2010

Multiple wellbore stability projects in the Western Desert of Egypt identified a strong sensitivity of the breakout gradient to wellbore inclination and a weak sensitivity to wellbore azimuth, from the Abu Roash to the Alam El Bueib formations. The breakdown gradient shows strong sensitivity to both wellbore inclination and wellbore azimuth. Tensile failures are a problem only in high deviation wells (deviation more than 55–60°) where the breakdown gradient will in general be lower. For highly deviated wells, the occurrence of tensile failure can be reduced by drilling close to the minimum horizontal stress direction.

Breakout can be tolerated to some extent, so planning the drilling mud weight to completely eliminate it is not necessary. The extent to which breakout can be tolerated depends on the well deviation, as cuttings become more difficult to evacuate as the well deviation increases.

As losses are very common in most of the Western Desert formations, the optimum drilling mud weight should be formulated as a balance between the risks caused by breakout and mud loss.

Understanding the main causes of rock failure and applying the recommended failure mitigation measures resulted in successfully drilling four deviated wells in the area.
Combining Selective Stimulation with Tailored Perforating Improves Injection Profile in a Carbonate Reservoir: A Case Study
Authors: Al-Gub Jamal M.A. , Horikoshi Tsuneo , Ichikawa Kazutoshi , Salsman Alan , Ali Neyaei Fardin , Vasquez Fidias
Published: February 2010

In a multi-layer heterogeneous carbonate reservoir in which production and injection is being carried out, one of the biggest challenges faced is to produce/inject evenly from/to the different layers. At elevated temperatures this heterogeneity limits the success of conventional stimulation techniques. A novel acid diversion technique involving selective stimulation and tailored perforation design techniques was applied in an offshore UAE well to improve injectivity in a multi-layered heterogeneous carbonate reservoir.

The well in question was re-completed from a dual string water injector well to a single string gas injector re-perforated in four different sub-zones. Well test and production logging data were used to estimate permeability and flow profile before the workover. These data were then used to run NODAL analysis, stimulation simulation, and perforation simulation models. The final workover proposal called for: Perforation over the same interval as was previously perforated using different gun and charge sizes to establish controlled injection based on the different zones permeability.Optimized coiled tubing (CT) selective stimulation using high strength retarded acid pumped in stages with a self diverting acid.

The well injection performance was dramatically improved as evidenced by the gross injection value and the injection profile obtained in a post treatment production logging run.

This paper details the planning, execution and final evaluation of this job which is unique in that the same interval was tested twice, before and after workover, after being completed using different perforating and stimulation techniques.
Case Histories of a New Family of Setting Tools for Ultra-Deep and High-Temperature Well Conditions
Authors: Kessler Calvin , Hill Jim , Housden Richard
Published: February 2010

A new generation electro-mechanical downhole power unit for setting and retrieving packers, bridge plugs, whipstocks, subsea tree plugs, and other downhole devices has been recently developed and deployed. The new Downhole Power Unit-Intelligent, DPU®-I tool, is designed to operate at high temperatures and extremely high pressures (400°F, 30 Kpsi) and to provide up to 100 K-lbf setting force. The increased force for either setting or retrieving downhole devices is independent of hydrostatic pressure and provides an alternative to jointed pipe or coiled tubing interventions, which were previously required to obtain high setting forces. New to the industry is the ability to monitor the downhole line tension, stroke length, setting force, the rate at which the force is being applied during the setting operation, and force at which the DPU-I tool detaches from the downhole device in real time at the wellsite or remotely by means of global satellite communications. This new functionality enables well-completion experts to remotely monitor the setting or retrieval operations 24 hours per day, seven days per week. It also provides a record of the setting operation for risk mitigation and for developing and improving best practices. This new downhole power unit conforms to our Digital Asset® workflows used to model, measure, and optimize customer assets.

The slow-controlled setting operation enables the slips or other anchoring mechanisms in the device to be set and to fully engage the casing/tubing and for the elastomer sealing elements to conform to the casing or tubing ID. This function is extremely critical in highly-deviated well conditions and when using casing or tubing with high rockwell hardness. Unlike setting devices that use explosives, military or governmental escorts are not required. In addition, single-lift heli-operations can be used. This tool does not require radio silence operations, and there is no non-productive time associated with tool redressing between runs. Tool sizes are available for well intervention in 2–3/8-in. tubing through 13-3/8-in. casing and can be tractor-conveyed in high-angle or horizontal wells.
Application of Specific Designed Bits and Eccentric Reamer for Deep Gas Wells in the Nile Delta Enables Operator to Achieve Significant Cost Savings on Drilling Wells
Authors: El Seginy Ahmed , Bohannon Ricky , Fayez Mohammed , Ekstrom Darren , Hussain Sameh
Published: February 2010

In 2008 &2009, Dana Gas continued on their deep Gas development program in the Nile Delta region of Egypt. These wells in the past had proven problematic in drilling because of high formation pressures and compacted shale in some intervals & almost the aligned curves (very narrow window) between the pore pressure & fracture gradient in other intervals.

Similar wells drilled in the past required both roller cone and PDC bits to complete the various sections. Because roller cone had unacceptably low ROP, Dana Gas determined PDC would offer the best option to efficiently drill these sections, therefore offering the best chance for success. Contingencies were considered for fallback to roller cone if necessary. Also in the contingency was the use of eccentric Ream While Drilling tool to enlarge the hole across a high pressure zone which would enable us to set an expandable liner and continue drilling to TD with a larger hole and avoid potential problems associated with slim hole drilling.

In the preplanning stage, Dana Gas drilling team closely examined new technologies which would allow us to achieve our goals, especially drilling the demanding deep highly pressured zones. The entire BHA was engineered to ensure the ROP and directional requirements would be met. A team was organized to aggressively seek technology/best practices that would efficiently deliver well objectives. The team identified the poor ROP in the compacted shale sections to be a primary obstacle as well as dealing with the potential zone with high pore pressure. BHA and PDC bit technology was a key focuses in optimizing the 12 ¼″ and 8 ½″ sections. Due to this careful planning and collaboration between Dana Gas and service providers, objective in the 12 ¼″ section on SHARABAS-1 and 8 ½″ section on EL BASANT-3 wells drilling with new designed PDC was achieved by increasing ROP and realizing significant savings. By applying new technology the 12 ¼″ section on SHARABAS-1 was drilled 328% faster with a savings of US$ 122,445.00 and the 8 ½″ section on EL BASANT-3 was drilled with a 37% higher ROP with a savings of US$ 34,517.00 than the direct offsets.
High Resistivity High Water Saturation Addressing the Problem to Avoid Water Production
Authors: Salah A.. , Hassan S.. , Sabra M..
Published: February 2010

Belayim Land field is one of the oldest and largest oil fields in Egypt. It produces oil from many sandstone reservoirs. Oil is produced from 4-30 ohm-m resistivity in Belayim Formation, while to the contrary, in Rudeis Formation, 70–80 ohm-m resistivity is producing water. Rock characterization program was planned for Rudeis Formation using core material. It includes porosity, permeability, thin section description, SEM, wettability, relative permeability and capillary pressure by mercury injection to obtain pore throat size distribution. The wettability of the reservoir rock was determined by Amott method and proved to be strongly oil wet. The wettability controls the position of fluids within the pore network, where in oil-wet the water saturation distributed as poorly connected droplets within the macro-pores and filled the micro-pores.

To simulate the saturation history of the reservoir, restored-state samples at irreducible water saturation were flooded with water to perform electrical resistivity measurements. Non-linear curves were obtained during the electrical resistivity measurements. Two saturation exponents (n) values were proposed to reflect the mechanism of forming continuous water film from the water droplets. The inflection point between the two (n) values was used to determine the resistivity cutoff below which water is produced. In addition, it represents the water saturation cutoff which was confirmed from the calculation of fractional flow of water from relative permeability measurements. The production data confirm the use of variable (n) to monitor the water saturation in oil-wet reservoirs.
Forecasting Reservoir Management Through Integrated Asset Modelling
Authors: Ursini F.. , Rossi R.. , Pagliari F..
Published: February 2010

The main challenge of Integrated Asset Modelling (IAM) is to couple dynamic reservoir and surface facilities models into a single integrated tool that allows the simulation of the whole oil field system. It is possible to take into account the following issues in a realistic way: pressure interactions between surface and subsurface, identification of system bottlenecks and backpressures, the system constraints, the mixing of different fluids and flow assurance.

An integrated asset model has been developed for an onshore Algerian asset which comprises three oil reservoirs connected through a surface network system to the same plant.

The controller program used for the simulation is Resolve, by Petroleum Expert. It enables the integration of the network model (GAP) and the reservoir models (Eclipse).

The results of the simulations show that IAM is able to reproduce the current field production data with an acceptable accuracy. Therefore, it can be used for forecasting purposes in order to evaluate different scenarios in terms of production rate and final oil recovery.

Two different IAM scenarios have been evaluated: constrained and unconstrained by a maximum oil production rate. The results have then been compared with the field behaviour simulated with the stand alone Eclipse models. The analysis of the IAM approach effect on the production profiles with or without the maximum oil rate constraint demonstrates that the integrated Asset Model is a powerful tool providing useful guidelines for field management in addition to a greater accuracy in the production forecasts and final oil recovery.
Improving Deep-Well Economics with Foamed-Cementing Solutions
Authors: El- Seginy Ahmed , Atta Abdel Azim , Kashif Omar , Zanaty Akram , El Sawah Khaled , Waheed Arshad
Published: February 2010

The practice of deep-well drilling (i.e., reaching depths of 15,000 ft or more) has been increasing for more than three decades with well costs increasing as record depths are continually challenged. The demand for gas has generally supported this drilling activity, nevertheless the pursuit for drilling the most economical well continues. This paper presents a case history of cementing a long, intermediate casing string. Such casing strings are strategically placed covering a large section of the drilled hole straddling as close as possible between the lowest fracture gradient and the highest pore pressure in the drilled section. Such a design helps minimize the number of casing strings required for the well, thus helping to reduce the well cost. While it might be possible to drill the hole by maintaining a balancing act between flow and loss situations, the cementing challenges remain to be tackled.

The use of foamed cementing has addressed the issue of cementing in a lost-circulation situation and controlling the flow from a gas zone found within the same interval. When compared to conventional cement jobs, foamed cement was not only superior in technical design but provided several cost-saving benefits that many potential users might be unaware of. For example, the bulk cement-volume requirement dropped by a factor of 1.72, provided a cost saving of approximately 35 to 40%, and reduced the bulk equipment footprint from 1,560 ft2 to 936 ft2. The job-time also decreased by three hours. These discrete savings combined are significant.

Though this solution brings much benefit to operators, it is still regarded as an unconventional cementing solution. This paper provides a case history, economic analysis, physical properties, and developmental background of foamed cementing that should help operators see its benefit and use.
Innovative Application of Foamed Cement for Zonal Isolation of a Tieback Casing across Highly Corroded Casing
Authors: de Weerd Arie , Al Hanshi Salim , Al Aghbari Salim , AlFadhli Abduallah
Published: February 2010

Drilling a surface hole with total losses through shallow aquifers is normal practice in Oman and most of the Gulf region. If losses cannot be cured while drilling, and the casing cement does not return to surface, required zonal isolation is most likely being compromised.

During the life of the well, flow behind the casing from the shallow aquifers results in accelerated casing corrosion that compromises the integrity of the well and results in relatively costly workover operations to restore the well and allow it to be operated.

Squeeze cement that repairs each corroded section of casing is a relatively high-risk and expensive operation with a low chance of success.

During a workover on one of the water-injection wells in North Oman, severely corroded 9 5/8-in. production casing was confirmed. The initial investigation confirmed multiple leaks in the 9 5/8-in. casing, of which the exact location was difficult to establish; however, it was expected to have resulted from a failed 13 3/8-in. surface casing caused by corrosion from the shallow aquifers. Communication between the 9 5/8-in. production casing and the 13 3/8-in. surface casing was confirmed in multiple zones. Different options were evaluated to restore the integrity of this well. The options evaluated included the use of mechanical casing clads (expandables) to fix each corroded section in the 9 5/8-in. production casing before running a 7-in. cemented tieback string and the option to squeeze cement across each corroded section in the 9 5/8-in. production casing before running a 7-in. cemented tieback string. Both of these options were abandoned because of economic concerns and low chances of success. It was decided to approach this integrity repair differently by running a 7-in. tieback casing to surface and using foamed cement to cement the 7-in. tieback casing and existing corroded 9 5/8-in. casing to surface. To maximize the chance of success, the 7-in. tieback casing incorporated a multistage cementing collar to help ensure foamed cement returned to surface. The two-stage, foamed-cement job with controlled returns from two annuli might be considered to be the first of its kind, globally. The foamed-cement job was executed successfully as per program, with good foamed cement returns from both the 7-in. × 9 5/8-in. annulus and the 9 5/8-in. × 13 3/8-in. annulus. The overall job met all the objectives and this technique has been repeated successfully on subsequent wells with similar integrity issues.
Evaluating Steam Injection Profile with High Temperature Memory PLT
Authors: Samir Mohammed , Hassan Wael , Kamal Salah , Hassan Amr , Draz Mohamed , Waheed Arshad
Published: February 2010

The Issaran field, a heavy oil reservoir with estimated original oil in place (OOIP) of approximately 1.6 billion bbl of oil, was discovered in 1981. The producing horizons are the carbonate formations of Miocene age occurring from depths of 1,000 to 2,000 ft. The oil is of 9 to 12 °API with viscosity of 4000 cP at standard conditions. It was not until early 2000, after the crude oil prices rose to favorable levels, that a concerted effort was made to develop this heavy oil. Cold production from the fractured carbonate Nukhul reservoir (depth approximately 2,000 ft) was first targeted and the production from the field increased from 170 barrels of oil per day (BOPD) in 1998 to more than 2,300 BOPD in 2002. However, the Upper Dolomite reservoir, at a depth of 1,000 ft, held more than 50% of the OOIP, but did not produce.

Subsequently, a pilot project using cyclic steam injection was implemented on two openhole completions in the Dolomite reservoir and the production results far exceeded predictions, proving it to be commercially viable. This pilot scheme was expanded to two, seven-spot pattern wells and the total combined production from the Issaran field reached 5,000 BOPD in late 2008. Recently, however, the productivity of the Upper Dolomite wells has declined. The water cut has increased and the steam injection efficiency is becoming questionable.

Because the steam temperatures of nearly 600°F exceed the operational limits of conventional production logging tools (PLTs), they cannot be used for steam injection profile monitoring. In addition, wellhead control and operational safety concerns become challenging issues. One effective solution to the problem was to run high temperature Memory PLT (MPLT). These tools are built for high temperature service and can be run on slickline, making this a more cost effective solution. The three wells selected for the preliminary run of the MPLT service were also the first applications of this technology in the Middle East area.

The primary results have already shown deficiencies in the steam injection process because most of the steam is being preferentially injected into water-bearing zones. This paper provides a detailed review of the results from the PLT surveys and the completion strategy implemented to improve productivity and maintain project profitability.
Pore Pressure Prediction and Pressure Regime Evaluation, Role and Contribution in Well Planning and Formation Evaluation Process, Gulf Of Suez Oil Fields – Egypt
Authors: Moustafa Selim Saber , El-Sayed Badawy Bassem , Mohamed Abdullah Khaled
Published: February 2010

The study aims to construct a simple and effective pressure regime model for Zeit Bay Field (as an example of one of Gulf of Suez Oil Fields which has a complex reservoir), which can assist the well planner to predict the pore pressure for the upcoming wells to be drill in the field. It aims also to find out the relationship between the constructed pressure regime model and the geological setting of the field.
Deepwater Drilling in Both Hard and Abrasive Formations; The Challenges of Bit Optimisation
Authors: Murphy Dominic , Tetley Nick , Partin Uyen , Livingston Denise
Published: February 2010

In mid 2007, two deepwater exploration wells made the first significant oil discovery offshore Ghana, West Africa (Jubilee Field). Drilling of the first two wells and subsequent appraisal wells indicated hard and abrasive formations, notably in the 12-1/4" reservoir sections, where up to four bits were needed using a combination of polycrystalline diamond compact (PDC) and tungsten carbide insert (TCI) bits. Therefore amongst the many project challenges there were significant drilling challenges to overcome. The primary goal was to drill the 12-1/4" section in one run, with the benefits of substantially reducing drilling time and costs where full-spread operating rates are in excess of $1MMUSD/day.

To address these challenges, the drilling team adopted a holistic planning approach prior to drilling the first development well. This used, in conjunction with a detailed analysis of the offset performance, a 4D finite element model that accurately predicts the performance of bit and bottom hole assembly (BHA). This approach allowed a fundamental understanding of the proposed system and its behaviour. The goal of drilling the section in one run was achieved far sooner than would have been expected using "trial and error" methodology, but with high vibration levels. Ongoing optimisation of the dynamic model with the actual down-hole data justified a BHA change to reduce vibration levels. Subsequently, the changes made to the BHA successfully reduced vibration levels, more than doubled rate of penetration (ROP) and facilitated good quality log while drilling (LWD) data.

With the high cost base of deepwater drilling activity, optimisation solutions that can be applied before and during the drilling process will make significant contributions to the overall project economics. Efforts were therefore applied to making the best pre-well bit and BHA selection, then analysing and understanding initial results, with an emphasis on maximising any learning and incorporating recommendations into the subsequent well. On the Jubilee Project, on-going optimisation can now focus on maximising overall drilling performance.