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IPTC 2014: International Petroleum Technology Conference
- Conference date: 19 Jan 2014 - 22 Jan 2014
- Location: Doha, Qatar
- Published: 19 January 2014
301 - 354 of 354 results
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New approach to hydrocarbon migration in the Polish Carpathians based on outcrops analyses
Authors L. Grzegorz, M. Irena and J. LeszekThe research was carried out in different tectonic units of the Polish Carpathians. Three stages of migration were indentified with the use of fluidal inclusions in cements analyses and bitumen traces in the pore space. The main migration paths of hydrocarbones are usually mélange tectonic zones revealing signs of diversified mineralization. These out-of-sequence thrusts may demonstrate the connection with the Carpathian basement. Location of hydrocarbons reservoirs along mélange and tectonic active zones, which form the flower structures, suggests the possibility of migration of hydrocarbons from the very deep zones subsidented within the Central Carpathian Depression (CCD) graben. Hydrocarbones generated at great depths migrates along mélange and active tectonic zones. These flower structure, consisting of network of fractures, in which crucial role in hydrocarbons migration plays the most active tectonic zone (so called master fault) plays a main role in hydrocarbones accumulation.e.g. CCD margin zone is an essential element for the process of charging these flower structures with hydrocarbons. Mineralogical, petrographical and geochemical (bitumen extracts, biomarkers) analyses were performed on sediments trapped in mélange zones. Completed studies have shown diversified mineralization processes and bitumen type along the main zone of the tectonic mélange. This is related to the depth of mélange zone rooting and fluid migration from the Carpathian basement rocks. Determination of hydrocarbons generation, its nature and the origin of crude oil trapped in mélange zones have a great impact on new directions in oil exploration in the CCD area.
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Recent Advancements in Vessel Desanding Technology
Authors A. Opawale and T. AbdallaProduction of formation sand and other solids with wellstreams has been a big challenge in the petroleum industry. Presence of sand in the production stream can cause erosion of upstream facilities and – even more commonly – clogging of flowlines and accumulation in production vessels; reducing residence time and performance of separator internals. Several methods have been applied in the petroleum industry to remove deposited sand from production vessels. Some of the drawbacks with these technologies are: localized sand removal, excessive use of water, interference on vessel liquid levels, compromise of water and oil quality, risks of clogging, huge sand system infrastructural size etc. Direct consequence of these situations would be unmanageable disturbances on production operations, and eventually leading to unplanned shutdown, and production loss. Recent innovations on design of vessel desanding internals at FMC Technologies are the Dual and Single Vessel Desanding Systems. While the dual desanding system integrates a set of systematically arranged jet nozzles and a novel hydrodynamically designed suction system, the single desanding system is a unique combination of a smart elliptical fluidization technique and suction in a single compact design. This paper presents both technologies, with special focus on their developments and qualifications. Case studies are presented; highlighting the benefits of the new technologies, as well as their application possibilities.
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Integrated Analysis of Borehole and Surface Seismic Data to Resolve Seismic Uncertainties in the Gulf of Suez
Authors M.S. El-Hateel, P. Ahmad, A.H.A. Ismail, I.A.M. Henaish and A. AshrafSeismic imaging in the Gulf of Suez is severely affected by salt plays, strong multiple contamination and raypath distortion etc. Consequently, geophysicists face challenges while interpreting the existing surface seismic and planning new wells, both in time as well as depth domain, and encounter surpirses while drilling. Borehole seismic is commonly used to address some of the seismic issues, which could also result in big uncertainties if not planned properly in challenging environment. In this paper, we present case studies from two areas in the Gulf of Suez where borehole seismic surveys were conducted in different configurations in wellbores with different geometries. Logging programs were defined after pre-survey ray trace modeling simulating different scenarios and careful planning considering the operational and geological challenges and logistics. Full waveform processing of well data resulted in much higher resolution 1D to 2D images in time and depth. Borehole seismic images were integrated with the existing surface seismic. In the first area, integrated analysis helped in horizon and structural interpretation revealing features not seen on low resolution surface seismic time and depth cubes. Seismic uncertainties for shallow as well as deep targets were resolved and fault interpretation was refined. Additionally, integrated analysis helped to detect new faults successfully, indicating new promising area for future development drilling. In the second area, integrated analysis confirmed presence of multiples in the surface seismic resulting in the target horizon deeper than expected, which was interpreted shallower all over the area. Analysis also confirmed change in the depositional environment in the area indicating a new block to be studied and estimated.
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Optimizing Reservoir Testing Operations With Downhole Wireless Telemetry System
Authors C. Acar, A. Aljifri, Y. Bekkhouce, M. Maalej, I. Nwogbogu and S. VannuffelenA new wireless telemetry system has been field tested in a variety of conditions in Middle East with excellent reliability. This wireless system enables bidirectional communication between the surface and downhole tools during testing operations by using acoustic signal. The wireless telemetry is used to transmit bottomhole pressure and temperature to the surface and permits control of downhole tools. This paper will describe the operating principle of the wireless system, present examples of how this system has been used to optimize the testing operations and summarize the key benefits achieved. The real time downhole data, compared with memory data has shown good match, has been streamed to client office successfully in real time, realized benefits from the operation and reservoir aspects for a vertical deep offshore well: Efficient management of wellbore events; providing operational awareness about tools status; refining the test sequences in real time, verifying underbalanced prior to perforation, monitoring stimulation pressures at sandface to avoid fracturing, updating the reservoir interpretation in real-time, optimizing the duration of flowing well sequences (clean up) and verifying the achievement of test objectives prior to retrieving DST string.
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Giga Cell Compositional Simulation
More LessSimulation models are often compromised (coarse cells, property up-scaling, incomplete physics), due to limitations in simulator technology and access to high computing power. Both computing power and technology have vastly evolved over the past 30 years. Unfortunately, previous choices made in the legacy reservoir simulators have limited their ability to adopt, and hence prevented them from harnessing these advances in an optimal fashion resulting in inefficiencies in parallel runs. We present the results of a next generation highly scalable commercial simulator on a Giga cell multi-component, compositional model of a gigantic field with several hundred wells and several years of production. The previous model was a 5.7 million active cell, multi-component compositional model that did not properly capture the main lateral and vertical heterogeneities. These heterogeneities consist of very thin high permeability streaks that play a major role in the pressure depletion. With the acquisition of a next generation simulator technology, a higher resolution model, with 47 million active cells was built. The performance of our next generation simulator, complemented with in-house developments, was a substantial 4-fold faster in CPU time than the same case using a legacy commercial simulator. However, the average cell size was still in the order of hundreds of meters laterally for this new model. A refinement of the cell size resulted in a billion cell (Giga) model. This model was simulated using our high-performance cluster computer. We also discuss the challenges of the simulation workflow in terms of pre-post Processing and IT environment.
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Sub Sea Compression at Ormen Lange
By R. RijnbeekOne of the most technically demanding developments on the Norwegian Continental Shelf, the Ormen Lange field is located 120 km offshore in 1000 meters water depth in the Møre Basin in the Southern part of the Norwegian Sea. It is a complete subsea development comprising four wellhead templates that tie back to an onshore gas processing facility at Nyhamna, where gas is dried and compressed before export to the Langeled pipeline via the Sleipner platform to the UK. The deep water and the seabed conditions have made the development very challenging and have necessitated novel technologies for the base project. The need for depletion compression was recognized from the initial development stages of the field and the Permit to Develop and Operate required the license partners (Shell, Statoil, Petoro, ExxonMobil, and DONG Energy) to develop subsea compression technology. This has resulted in the development of a full scale operational pilot plant to prove that subsea compression technology is viable. This paper explores the challenges that the license and Shell as operator as well as the subsea industry have overcome in developing this novel technology and outlines the future plans for the eventual selection of subsea compression as the development concept for depletion compression on Ormen Lange and elsewhere.
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Wireline Retrievable Electric Submersible Pump: Innovative and Valuable Completion for Offshore Fields
Authors T. Dieuzeide, A.P. Bemba, D.H. Kusuma and G. AndersonAll of Total E&P Congo’s production comes from offshore wells and the majority of these producers use secondary lift, mainly gas-lift and ESP (Electrical Submersible Pump). The efficiency of ESP and high delta pressure operation means that all new field developments use them along with a number of gas-lift conversions. One disadvantage of using ESP is the need for frequent intervention which, when coupled with a high work over cost and subsequent deferred production, both due to dependence on available work-over vessels in the region, can lead to exceedingly high operating costs. Moving away from this rig dependency towards a lighter operation would mitigate these drawbacks and greatly reduce the operation cost of the ESP systems deployment. Those changes are possible with the Wire Line Retrievable ESP (WR-ESP) technology. An initial work over is to set permanent completion elements. When the WR-ESP is retrieved, the tubing and the ESP power cable stay in place (permanent completion). The WR-ESP technology provides full bore access below ESP, short and light BHA, and uses permanent magnet motor (PMM) to increase the efficiency. Well screening for the pilot installation were done for Total E&P Congo wells. The selected candidate (Field A well) allows a simple and robust completion with little operation complexity. High safety standards are guaranteed during production and also during future well intervention. The use of slick line unit for ESP change-out is the key of this technology due to its flexibility, rapid mob-demobilization, and small operational cost compared to offshore pulling unit or rig. This bold way of deploying ESP is possible due to two main technical innovations:
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Soft Torque Impact on Drilling Performance in Qatar
Authors F. Attar, R. Grauwmans and O. IkhajiagbeThe drilling industry has identified torsional stick-slip vibrations as one of the obstacles to the progress and efficiency of drilling operations, and a common cause for tool failures. Therefore, significant research into different technologies and methods has been conducted to mitigate this issue. The Soft Torque Rotary System (STRS) is one of these technologies which aim to actively dampen these vibrations from surface. This system was originally developed by Shell in the early ‘90’s. In recent years, the implementation of the original Soft Torque technology has been improved and this improved implementation is now rapidly being deployed on the Shell global rig fleet. In 2009, Qatar Shell was one of the first to use this new Soft Torque implementation for the Pearl GTL development wells. Gulf Drilling International, GDI, has also taken up this technology and installed it on their Al-Khor jack-up rig, currently on contract with Qatar Shell. This paper highlights the experience Qatar Shell had by comparing the drilling performance on Pearl GTL between wells with STRS installed and those that did not have STRS. This paper also details the experience and improvements seen as a result of the STRS installed on Al- Khor rig and the tests conducted with having the STRS system switched on and off in the same formations to compare its efficiency. Finally, this paper will also cover Shell’s global experience with these systems.
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Mechanical Pipe Cutting in ERD Wells with Pipe Under Compression
Authors R. Macfarlane, B. Schwanitz, M. Aguirre and J. GreenleeIn order to reduce rig time during workover operations, a new electric line (e-line) mechanical pipe cutting tool was deployed rigless in four ERD wells in the Middle East. The 4-1/2” production tubing of several high deviation wells needed to be cut and pulled prior to a tubing change-out campaign, commencing February 2013. This particular mechanical cutter was chosen for its non-explosive design, where a rotating crown removes pipe wall by grinding, creating a smooth bevelled surface without shavings. This eliminates the need for a polishing trip, allows the pipe to be severed even when under compression, and leaves a cut profile in the well which is ideal for subsequently fishing. Also, this type of cutter incorporates a ‘fail-safe’ mechanism that prevents the tool from becoming stuck following the cut process, and the cutting crown design precludes the tendency for sticking, which is a major concern with other mechanical cutters. In January, 2013, a system integration test was conducted to determine whether a grinding face cutter could actually cut a pipe in compression. A jig was set up to provide 20,000 lbs of compressive force on a 4-1/2”, 12.6 lbs/ft pipe. The cut was made in 36 minutes. The subsequent rigless operations on four wells resulted in six successful cuts, without the requirement for the pipe to be put in neutral weight or tension. The amount of compression at the cutting depth was unknown, but at least 10,000lbs, as per the packer setting procedures. A key benefit of mechanical pipe cutters is that they eliminate the use of explosives and chemicals which can pose HSE and operational risks, especially when simultaneous operations are being conducted. The transfer and handling of explosives may also cause additional logistical requirements and significant delays, as safety procedures are employed. In addition, this mechanical solution eliminates the need for dress runs, and tubing recovery is optimized from a rig time perspective. This paper will discuss the operational steps taken to make the pipe cuts, a description of the new pipe cutting tool and lessons learned to improve future operations.
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Step Change in Shallow Water Reflection Seismic by Advances in De-Multiple Techniques
Authors H. Rønde, C. Huegen, L. Madsen, J.R. Henderson, M.I. Emang and S. HallidayA high-resolution survey with a total of 2300 km2 of 3D reflection seismic data was acquired over the Al Shaheen Field, Block 5, offshore Qatar, from October 2006 to April 2007. Reverberations from the hard shallow water bottom and other types of noise limited the value of the original processing. Re-processing using new technologies has produced a step change in quality resulting in cleaner images for interpretation and superior angle stacks for inversion. The multiples were removed by applying an enhanced processing workflow based on a predictive, data-driven algorithm. The workflow involved attenuating short-period water-layer related multiples – a process that is referred to as shallow water demultiple (SWD). The SWD method makes use of water-layer multiples in the data to reconstruct the missing water-bottom primary reflection, and then uses the reflection for predicting these shallow multiples. The method takes into account the spatial varying nature of the subsurface. Since the multiple model predicted by SWD has similar amplitude and phase as the input data, very short matching filters can be utilised in the adaptive subtraction process. These processing improvements have influenced a broad spectrum of interpretations such as better structural representation including fault mapping and improved understanding of facies. In conclusion, detailed and careful testing has resulted in new added value from this large high resolution 3D data set by applying technologies that were not available when the data was acquired and processed in 2006-2008.
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Improvements in Reservoir Fracture Network Characterization Using High Resolution Logging While Drilling Resistivity Images In Extended Reach Wells Under High Stick Slip Conditions
Authors S. Finlay, N. Bounoua, F. Irani, J. Rasmus, C. Fulton, S.C.Y. Ha and L. PontarelliMiddle East carbonates frequently are heterogeneous in nature, encompassing variable pore types, strong diagenetic overprints, variable wettability and fracture networks amongst other effects. Resistivity borehole images have long been an integral constituent to understanding their complexity and unlocking volumes. High resolution LWD resistivity images were first introduced in the 1990’s, however as downhole environments became progressively more challenging, resistivity images suffered from the dynamic acquisition environment resulting in severely degraded images. The Al Shaheen field has been developed with Extended Reach Drilling (ERD) wells, and wells of 30,000 feet are commonplace. Early LWD resistivity image data suffered from excessive stick and slip, with approximately half of the wellbore suffering from poor quality image data, degrading with depth. The outer portion of the wellbore is prohibitive to impossible to access via conventional drill pipe conveyed tools, resulting in an absolute requirement for high quality LWD resistivity images. The new methodology redefines the acquisition and processing methodology, resulting in images unaffected by stick slip with a 100% success rate in the most challenging of ERD environments. This paper illustrates the improvements in logging while drilling images (LWD) and subsequent fracture network characterization as a result of implementing a new image acquisition strategy and processing algorithm. The paper explores the close collaboration necessary to drive the innovation to dramatically enhance existing technology, and demonstrates the results with comparisons of the LWD images using the old and new methodologies.
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Dilute Surfactant Flooding Studies in a Low-Permeability Oil-Wet Middle East Carbonate
Authors M.V. Bennetzen, K. Mogensen, S. Frank and K. MohantyThe majority of alkali-surfactant-polymer (ASP) applications to date have targeted medium-to-high permeability sandstone reservoirs containing reservoir brine with moderate salinity and hardness. Surfactant flooding experiments have been reported in carbonates, but applications targeting oil-wet, low-permeability limestone rock are still uncommon. This paper contains results from laboratory core flood tests performed on an oil-wet limestone rock from the Al Shaheen field, offshore Qatar. The rock samples investigated had approximately 30% porosity and 5 mD permeability, whereas the reservoir brine had a salinity of about 120,000 ppm of which about 10,000 ppm were divalent cations. The first screening step involved testing combinations of several commercial surfactants, co-surfactant and alkalis. Two costeffective surfactant systems were identified. The first system, denoted ITR, was capable of reducing the interfacial tension below 0.001 mN/m over the required range of salinities. The second system, referred to as WA, effectively altered the wettability from strongly oil-wet to intermediate-wet. Static adsorption was measured to be low for both systems. No polymer was used because the permeability was very low. Both surfactant systems yielded significant incremental oil, when injected in tertiary as well as in secondary mode. The ITR system recovered almost 95% of OIIP but required many pore volumes since the cores remained oil-wet. The WA system, on the other hand, recovered some 85% of OIIP in secondary mode but achieved this with much fewer pore volumes. The WA system was subjected to extensive analysis. Relative permeability curves from unsteady-state core flooding data were derived and experiments were simulated with UTCHEM. The main conclusion from the extensive laboratory work is that surfactant systems can be tailored to recover a significant amount of oil from a low-permeability carbonate reservoir. Wettability alteration may assist in unlocking significant volumes of additional oil from this complex, offshore field.
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Theory and Experimental Setup of the New Rise In Core Reservoir Wettability Measurement Technique
Authors S.G. Ghedan and C.H. CanbazReservoir wettability has direct impact on the relative movement of reservoir fluids and oil displacement efficiency by EOR techniques. The industry standard wettability laboratory techniques of Amott, USBM and modified Amott/USBM are very time demanding due to its complex experimental setup and procedure. This paper describes the theory and experimental setup and procedure of a new wettability laboratory technique. Rise In Core, RIC, technique is based on a modified version of the Washburn Equation. The modified equation could be solved for the wettability contact angle by only substituting the slope of a fitted straight line of the square of core sample mass change with time, resulting from either water imbibition into oil saturated core sample, and/or vice versa. A constant of the equation, that is characteristic of the rock type, needs to be determined prior, however, by conducting an imbibition experiment of a reference liquid into air saturated twin core sample. The reference liquid completely wets the core sample with zero contactangle. The new technique was applied to measure the wettability of Berea sandstone core samples. The wettability of natural outcrop cores was found to be weakly water wet. Experiments conducted on neighboring samples, produced similar wettability results, indicating good repeatability. The applicability of the RIC in other wettability regions was also tested, resulting in repeated strong wetness for samples that were artificially treated to be either strongly water wet, and oil wet. The technique was also compared to the existing industry technique and proved to provide equivalent and more consistent wettability measurements for more than ten twins of carbonate core samples. RIC technique is theoretically sound, and requires simple experimental setup and procedure. Moreover, it determines wettability in terms of contact angles rather than wettability index. It is more consistent and applicable to all wettability regions.
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Supporting the National Agenda: Education & Capability Building for the Youth of Today
Authors A. Garg and M. Al-KaabiBuilding a competent National Operator and Technician workforce to support the Oil and Gas sector is an increasing priority for resource rich countries globally. School leavers in many parts of the world today find the Petroleum Industry less attractive than other Industries and their need for structural development that builds a solid foundation that is portable across their chosen employer is a critical part of the employee value proposition. Certifications against a clear competence driven program are vehicles that have great appeal. This paper will describe the partnership between the Qatar Petroleum Corporate Training Department, CNA-Q, (State College), QiTS (technical school) and Royal Dutch Shell in delivering a new generation of competent national technician and operations staff. The purpose of the TPP program is to build the foundation skills necessary for working at the technician and operations (certificate) level in the Energy and Industry Sector in Qatar. The competence based training program leads to the Technical and Further Education (TAFE) certification. Harnessing the principles of blended learning, its building block approach has a particular emphasis in practical workplace learning. The combination of a state run college program, based on international industry standards and direct workplace application enables the progression from knowledge to skill in a thorough manner. In addition to Line Supervision, the paper will describe the TPP Support Team whose role is to coach and monitor to ensure competence levels are attained and customized to the needs of the asset team when needed. Aligning theoretical content with plant specific (Pearl GTL) needs ensures a seamless start at the workplace for the individual. Following graduation, the next phase of development is outlined via a clear Work Area Learning Program (WALP). These highly tailored WALPs are the primary tools for an operator trainee to acquire deeper proficiency in the work place whilst building on the basis. This increases their time to proficiency and builds a solid foundation for their future progression.
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Integrity and efficiency in LNG transfer operations with flexible hoses
Authors E. van Bokhorst and A. TwerdaThe work presented contributes to the LNG supply chain by the development of a validated calculation model for corrugated flexible hoses or pipes developed for LNG Transfer. The model builds upon experience gained by TNO Technical Sciences (Fluid Dynamics) in a large number of flow tests carried out on hoses in a large range of diameters from 4 to 18-inch. LNG transfer rates are in general relatively high as the time involved should be limited from economical point of view. In large scale offshore LNG transfer, flow rates up to 5000 m3/h are applied and in future flow rates up to 10.000 m3/h are foreseen. Typical values mentioned for offshore operations in tandem transfer range from 50 to 150 meters hose length and hose diameter up to 20-inch. The pressure losses in LNG offshore transfer, but also in smaller scale applications, can be considerable. The pressure loss depends on flow rate, length of the hose, internal diameter and internal hose corrugation geometry. High pressure losses will impose additional requirements on LNG pumps and might result in cavitation at the downstream end of the hose as the average pressure drops below vapor pressure. Furthermore the impact of local boiling phenomena due to heat-ingress and cavitation, possibly effected by vortex shedding along the internal corrugations, is not known. Once the gaps in the data base are filled a validated prediction model is available, which can be used in guidelines and standards. So far the EN1474 (part 2: Design and testing of transfer hoses) does not specify a maximum allowable pressure loss and the prescription of the requirement for the test is limited: “Flow rate testing (ambient or cryogenic): demonstrate that the hose is capable of operating at its maximum flow rate and confirm the predicted head loss” The final goal of the project is to obtain a validated prediction model for the calculation of pressure losses in LNG transfer with flexible multi-composite and metal hoses based on input of parameters as operating conditions and hose geometry. Also input for guidelines and standards in LNG transfer with flexibles such as EN1474 will be generated, which can be used in for qualification of LNG equipment.
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The Present-day Stress Pattern in the Middle East and Northern Africa and Their Importance: The World Stress Map Database Contains the Lowest Wellbore Information in these Petroliferous Areas
Authors M. Rajabi, M. Tingay and O. HeidbachKnowledge of the present-day stress field is vital for a range of earth science disciplines, including hydrocarbon and geothermal energy production, mine safety and seismic hazard assessment. The scientific importance of understanding the present-day maximum horizontal stress orientation has been demonstrated by the findings of the World Stress Map (WSM) Project, which has spent over 25 years building an extensive freely-available repository of present-day stress information as a collaborative project between academia, industry and government. The WSM project has revealed that the plate scale presentday stress is controlled by the tectonic forces exerted at tectonic plate boundaries. However, numerous studies in sedimentary basins have shown that stresses in the oil-patch can be complex, and controlled by both major far-field forces (plate boundaries, body forces from mountain belts) and intra-basinal forces, such as detachment zones, salt, faults and basin geometry. The World Stress Map project contains free and public information for over 80 basins around the world. However, the project contains almost no wellbore data for the Middle East and Northern Africa, despite this region hosting much of the world’s global oil production and extensive industry activity. To date, the World Stress Map Project only contains limited datasets from petroleum wells in Egypt, Oman and Iran – but no data at all for Saudi Arabia, Iraq, Libya, Algeria, UAE, Kuwait or Qatar. In this paper we first review different methods for determining and calculating the present-day stress pattern in the region, then we highlight the lessons learned from the World Stress Map project on the controls of present-day stress in the oil-patch. Finally, we focus in detail on the stress data that currently exists for the Middle East and Northern Africa.
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Applications of Geophysics to the Al Shaheen Field, Qatar, for Reservoir Characterisation and Field Development
Authors R. Lorenzen, L. Madsen, C. Huegen, T. Ting, J.R. Henderson, C.B. Raborn, A. Uldall, H. Cromie, V. Zampetti and M.I. EmangA comprehensive seismic interpretation programme was recently initiated with the purpose of further increasing the use of 3D seismic data for reservoir characterisation and field development in the Al Shaheen Field, offshore Qatar. Reprocessing of existing seismic data was part of the programme to ensure best data quality for the interpretation. The Al Shaheen Field is a layered carbonate dominated field with multiple reservoirs at different stages of development. Reservoir characterisation is a key driver for both new development areas in the field and for optimisation of existing development areas. Geological topics relevant to reservoir characterisation and field development where seismic data support the reservoir models include faults, reservoir architecture and properties. In this study we present results of integrated seismic interpretations aiming at improving the reservoir characterisation. The results span three of the important reservoirs: Kharaib, Shuaiba, and Mauddud. Through seismic interpretation and integration with geological data and concepts, a consistent field-wide fault framework has been defined. A complex channel system in the Shuaiba reservoir and clinoforms in Mauddud have been mapped. The porosity distribution in the Kharaib reservoir has been estimated using seismic attributes. Additionally all the main geological surfaces defining the general structure and stratigraphy have been mapped. For some results the confidence is high and they can be used directly in the reservoir characterisation and building of static and dynamic models. Other results are less certain e.g. porosity of the Kharaib reservoir. Where this is the case, the results are used to help define uncertainty ranges for the models, as well as enabling testing of different scenarios in the modelling. Properly integrated with all available field data, the value of seismic data is to help create a spatial understanding of geological features that cannot be achieved from well data alone.
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Refracturing in Old, Mature and Depleted Carbonate Reservoirs in Saudi Arabia for Production Enhancement
Authors A.R. Malik, T.M. Ogundare, Y.H. Ali, K.K. Waleed, D.A. Alaa, R.T. Sebastian and T. BukovacHigh temperature, low reservoir pressure, high permeability contrast, high H2S content, long perforated interval, production decline, existing hydraulically induced fractures, FeS scale, and mature and aging completions are some of the tough challenges encountered in certain carbonate reservoirs in Saudi Arabia. These wells require periodic mechanical descaling operations using coiled tubing. The reservoir suffers tremendous damage during the descaling process and requires restimulation to restore and/or enhance production. The damage is noticed to be higher in non-monobore completion. High rate matrix acid stimulation treatment has been often found not effective to restore and/or enhance production. Acid re-fracture treatment is required to bypass damage and achieve effective new etched fracture length, but the aging completion often disqualifies the well to be a candidate for refracturing treatment. The wells discussed in this paper have been acid fractured in the past and produce for over 20 years with significant production decline. The wells were isolated by pumping large volume of calcium carbonate (CaCO3) chips into the formation prior to the descaling operations. During the descaling of 4.5 in. tubing and 7 in. liner completion, additional near wellbore damage is unintentionally introduced into the formation from the precipitation and broken scale buildup from the wall of the 7 in. liner. Subsequently, acid refracture treatment was effectively placed allowing better and new stimulated rock volume in the depleted formation bypassing the induced near wellbore damaged. The post stimulation flowback analysis showed an improved productivity from mature and depleted reservoirs after the refracturing treatments. This paper focuses on the challenges of refracturing old, mature and depleted carbonate reservoirs, well candidate selection, and treatment design, execution and evaluation.
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Program Acceleration: A Case Study
More LessKaran Gas Program has successfully completed Saudi Aramco’s first offshore, non-associated gas development achieving record early gas in 2 years and 3 months with full production in 3 years and 4 months. Figure 1 shows completion of the first offshore non-associated gas production platforms. The Karan gas field is located offshore approximately 110 KM in Saudi Arabian Gulf territorial waters. It was discovered in 2007 and has a production capacity of 1,800 million standard cubic feet per day (MMSCFD) of natural gas. The Karan Program achieved the corporate objective of maintaining sales gas supply to Saudi Arabia from 2011 onwards by executing the 1,800 MMSCFD non-associated sour gas program. The increased gas supply will be utilized for power generation, water desalination, chemical feed stocks, and as sales gas. The increased utilization of natural gas for domestic consumption decreases the amount of fuel oil required, thereby freeing up that valuable commodity for export and commercial utilization. In order to meet its business objectives and provide value to its stakeholders, the program was executed under four sub – projects that were developed concurrently.
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Next-Generation Workflow for Multilevel Assisted History Matching: Visualization and Collaboration
Authors G.A. Carvajal, M. Maučec, A. Singh, A. Mahajan, J. Dhar, M. Villamizar, S. Mirzadeh, S. Knabe, F. Md-Adnan, A.K. Al-Jasmi, H. Nasr and H.K. GoelThis paper outlines the visualization and collaboration attributes of an automated workflow that integrates the computerassisted history matching (AHM), quantification of inherent model uncertainty, and optimization on production-forecast decisions. The workflow belongs to the group of smart flows for integrated asset management installed at the North Kuwait Integrated Digital Field (KwIDF) collaboration center. The workflow is facilitated through four interactive user interfaces:
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Installation of Long Interval Conductor String Across Challenging Offshore Drilling Environment
Authors K. Won, K. Muir, C. Chanpen, W. Thet, F. Noble and I.B. Budi UtamaConductor string installation has always proven to be key element process for a successful well construction in offshore project. However, challenging drilling environment such as rough current presents a huge resistance for the conductor string installation with conventional drilling technique. Previous offshore exploration activities have seen many case studies with failure on conductor installation causing significant delay on drilling operation consequently impacted with higher project cost. Non-retrievable casing drilling technology, has gained wide reception from operators in Asia Pacific region for drilling top hole sections in offshore project recent years. The high value realized in reduction on well construction costs and efficient installation process across challenging drilling environment has contributed to the high popularity of this innovative drilling technique in the region’s offshore work. A non-retrievable casing drilling bit has been successful in previous casing drilling application across Myanmar shallow water. The previous success has raised interest for an attempt in pushing deeper conductor string setting depth to simplify well design and determining the ultimate capability of this system in drilling a 549 m conductor string, the deepest 20-Inch string set with casing drilling technique in Asia Pacific region. A new Leopard SD casing connector with higher torque capacity was first time utilized on a casing drilling application in this project. This paper introduces the planning and implementation process of the long interval 20” casing drilling through challenging drilling environment in this project. In the paper it also discusses the detail running procedure, drilling parameters involved, operational results of the casing drilling bit, casing connector’s performance and lesson learnt from the project.
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An Accurate Volumetric Calculation Method for Estimating Original Hydrocarbons in Place for Oil and Gas Shales including adsorbed Gas using High-Resolution Geological Model
Authors J. Bruyelle and D.R. GuérillotThe emergence of liquid-rich and gas shale reservoirs presents major strategic opportunities and challenges for the oil and gas industry. Accurate estimation of Stock Tank Oil and Gas Initially In Place (STOIIP & GIIP) is one of the priority tasks before defining the reserves. An accurate method is proposed to calculate hydrocarbon volumes using high-resolution geological models taking advantage of huge improvements made during last decade in the field of characterization and geological modeling of unconventional reservoirs. This exact method provides fluids in place in reservoir and surface conditions with an extended black-oil formulation including condensates. The physic including the equilibrium between gravity and eventually capillary forces and adsorbed gas is fully respected using, for each lithofacies, the most accurate available geological description with 3D porosity distributions, Langmuir isotherms (Langmuir, 1918), capillary pressure curves, and thermodynamic data. Adsorbed and liquid-rich gases are considered. This method calculating hydrocarbons in place is the natural endpoint of any workflow devoted to the geological modeling of newly discovered reservoirs, particularly suited to heterogeneous reservoirs. The knowledge generated by this calculation has significant impact on fracturation programs to increase the recovery rate and field development planning.
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3D Imaging of Porosity Modifying Phases in Shuaiba Reservoir, Al Shaheen Field
Authors X. Marquez, T. Solling, S. Finlay, N. Bounoua and T. GagigiExisting porosity and permeability predictions in the Shuaiba reservoir of the Al Shaheen Field are largely based on detailed core observations and measurements that have been integrated with geochemical data and linked to robust conceptual models. This approach has been successful at predicting general porosity and permeability trends mainly related to deposition on the platform, barrier and basinal environments and the processes of dissolution and cementation; however, there is a lot of uncertainty in correlating and predicting the spatial variation of dissolution and cementation styles within each depositional environment. This uncertainty becomes larger when trying to identify rock types for petrophysical prediction and also to correlate the diagenetic patterns at field scale. The work summarized in this contribution demonstrates how we have gone beyond the classic characterization of diagenesis and have moved toward the quantification and 3D visualization of diagenetic products that modify the pores and pore throats. Present day porosity and permeability of the Shuaiba limestones in the platform area has been significantly modified by calcite and minor pyrite cementation, hence in this study detailed and calibrated paragenetic data have been integrated with 2D quantitative mineral and elemental maps obtained with the use of QEMSCAN and coupled with 3D images using an in-house micro-CT scanner. Meticulous segmentation of grey levels in the 3D micro-CT images allowed the recognition and quantification of the cement phases and corresponding porosity before cementation, which could then be reconstructed and used to assess the porosity at any given diagenetic stage. This integrated, object-based, approach has the potential to significantly improve our ability to identify rock types, to help predict the spatial distribution of porosity and permeability in the Shuaiba reservoir and to ultimately improve realizations of reservoir connectivity for flow simulation.
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3D Imaging of the Pore Network in the Shuaiba Reservoir, Al Shaheen Field
Authors T. Solling, X. Marquez, S. Finlay, N. Bounoua, T. Gagigi, T. McKay and A. Fogdenment and simulation of flow properties. As a complement to parallel studies of the plugs by conventional petrographic and core analysis techniques, a set of samples from four wells in the Shuaiba reservoir of the Al Shaheen field was analysed by 2D mineral mapping (from QEMSCAN) of polished plug sections, and by 3D tomographic mapping (from micro-CT) of subsampled mini-plugs, as a complement to parallel studies of the plugs by conventional petrographic and core analysis techniques. QEMSCAN showed a high variability in measured porosity and pyrite content over all sampled length scales, from millimetres (across the polished plug faces) to feet (with depth in a given well) to kilometres (across the four wells). The porosity from QEMSCAN was generally found to be in good agreement with that measured on the conventional plugs. Two mini-plugs of 5 mm diameter were scanned using helical micro-CT, one of which was subsequently analysed to segment the macropores, microporosity, calcite and pyrite. Comparison with the QEMSCAN results from the section of the “parent” plug showed consistency in estimated porosity and pyrite content between the two methods. Simulations of conductivity and absolute permeability were performed on subvolumes of the segmented tomogram, and displayed a strong variability with the location and size of the chosen subvolume, although the overall trends remained in good agreement with core analysis.
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Combining High-Definition Formation Microelectrical Imaging and Wireline Formation Tester for Improved Reservoir Characterization in High-Resistivity Low-Permeability Carbonate Reservoir
Authors M.S. Osman, W. Matter, W. Koerfer, J. Gao and M.E.Z. El-DemerdashWireline formation microelectrical imaging has been used for many decades to characterize reservoirs. The geological interpretation of image data is mainly used for structural analysis, fracture characterization, porosity analysis, heterogeneity analysis, rock typing, and facies classification. In addition, formation microelectrical images are commonly needed for complex reservoirs to help with the selection of wireline formation tester straddle packer locations. The quality of the data acquired using conventional formation microelectrical imaging tools may be degraded in highly resistive formations even with conductive mud because of the high noise-to-signal ratio, which can lead to fuzzy images with very few geological features visible. Phase shift, which is common in resistive formations, can result in reversed images, reversed contrast, and pad/flap mismatch, which can render the data unusable. A new tool for microelectrical imaging presents a solution to this problem by obtaining high-definition, full-coverage images in formations with moderate to high resistivity. This new technology was applied in a complex carbonate tight gas reservoir drilled with water-based mud (WBM). Conventional formation microelectrical imager data suffered from a huge phase shift, low quality, and low-resolution, with very few geological features visible. The high-definition formation microelectrical imaging resulted in much better data quality, which enabled the identification of the different geological features. The data obtained from standard and the high-definition formation imaging are presented and compared. Use of the high-definition data enabled positioning the wireline formation tester at the optimal zones. The new selected stations enabled proper fluid identification where pressures and samples were obtained. In addition, reservoir permeability data were obtained using pressure transient analysis. Pressure transient interpretation of the straddle-packer data corresponded well with the geological features observed from the high-definition images.
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Improving Relative Permeability to Gas in Tight Sandstone Formations by Using Microemulsions
Authors A. Rostami, D.T. Nguyen and H.A. Nasr-El-DinOne of the challenges in slickwater fracturing of tight sand gas reservoirs is post-treatment fluid recovery. More than 60% of the injected fluid remains in the critical near wellbore area and has a significant negative impact on the relative permeability to gas and well productivity. The trapped water could be due to capillary forces around the vicinity of the fractured formation. For strongly water-wet tight gas reservoirs, capillary forces promote the retention of injected fluids in pore spaces. Commonly available surfactants are added to slickwater to reduce surface tension between the treating fluids and gas. The problem with surfactants is that upon exposure to the formation, they adsorb on the surface of the rock. The addition of microemulsion to the fracturing fluid can result in lowering the pressure needed to displace injected fluids and/or condensate from low permeability core samples. This alteration of the fracturing fluid effectively lowers the capillary forces in low permeability reservoirs. This will result in removal of water and condensate blocks, the mitigation of phase trapping, and therefore an increase in permeability to gas. This paper examines the effectiveness of microemulsions in the improvement of fracturing fluid recovery. Coreflood runs using 20 in. Bandera sandstone cores with residual condensate and water showed that the percentage of permeability regained due to treatment with microemulsion solutions was up to 150% depending on type of microemulsion. An environment-friendly microemulsion formulated with a blend of a novel anionic surfactant, nonionic surfactant, short chain alcohol and water showed very good results in lowering interfacial tension between water and oil, when compared with competitive technologies. The performance of this microemulsion was excellent in high salinity fluid as well as low salinity fluid. It was excellent for solubilizing liquid condensates which can be found in wet gas wells. Contact angle of 63.45 degrees makes this microemulsion an optimal solution for cleanup of the near wellbore area. The resulting capillary pressure for a frac fluid treated with 0.25 wt% of this chemical in 2 wt% KCl is nearly 300 times lower than untreated fluid and 30 times lower than a fluid treated with competitive technologies.
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Study on Mechanism of Two-phase Flow in Porous Media Using Micro Focused X-ray CT
Authors K. Mikami and T. MukunokiA technology of X-ray Computed Tomography (CT) has become one of the popular techniques in the medical and engineering fields as a non-destructive testing method. In general, there are three kinds of X-ray CT scanners for medical, industrial and micro focused applications. In particular, micro focused X-ray CT (MXCT) scanners with high energy x-ray beam attaining high resolution have been drastically developed in a decade. Meanwhile, the study with respect to multi-phase flow in porous media desires to get more quantitative parameters of the particle shape and pore structure to clarify the mechanism, such as residual oil trapping. Nowadays, techniques of image processing and analyzing are very developed worldwide so that it has been available to evaluate pore structure and the fluid behavior without any destruction. The objective of this study is to understand residual mechanism of oil in sandy soil during water flooding. In this paper, a newly developed apparatus of flow injection for MXCT scanner and image analyzing technique were introduced and then, the pore scale and its distribution in the specimen were evaluated as the achievement of the first objective. Additionally, the cluster analysis was applied to each trapped oil blobs extracted from MXCT images. This image processing technique allowed quantitative evaluation to pore structure of specimen and trapped oil blobs.
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Back-Flowing of Injection Wells
Authors W.B. Bowen, R. Benkovic, M. Gunningham, M.R. Jaafar, M. Ghozali and A. Al-SadahIn the Al Shaheen (ALS) field offshore Qatar, injection wells have generally been back-flowed to remove solids introduced during drilling and stimulation, with the objective of enhancing injectivity. This is considered by many as “best-practice” in the industry. Data from the early back-flow period for injectors and the early production period for producers has been reviewed to try to identify “clean-up” events. Some apparently spontaneous rate increases were observed. Analysis of this data was found to be complicated because during the initial 20 days of production frequent choke size changes were made. Bottom-hole pressure data around the time the wells were opened was also found to be absent in most cases. An attempt to compare the injectivity of a few wells which were not back-flowed with analogues that were was also frustrated, due to variability of permeability and oil viscosity between wells. It was not possible to draw definitive conclusions. A new phase of drilling at ALS provides an opportunity to investigate the efficacy of back-flowing in a pre-mediated fashion. Special provisions will be made during the initial production period to evaluate whether or not the wells clean up. In addition a comparison will be made between the injection performance of pairs of injection wells which are located in areas with similar transport properties. For the injection well pairs, one injector will be back-flowed for a month while the other will be put on injection immediately after stimulation. In this manner it is hoped to demonstrate conclusively whether back-flow of ALS injectors enhances injectivity.
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E-Technology: A Key for Excellence in Training
Authors D. Dekeyser, L. Machhour and V. VedrenneTraining is a major challenge in oil &gas companies because of the rich diversity of cultures and generations. Since our aim is to provide the same skill development opportunities to every Total employee, we need to develop a worldwide access to quality training that is up to our standards. The expected high rate of seniors’ retirement imposes the need to find ways of preserving departing experience. Our technical studies are complex and use concepts and tools that rapidly develop with time. Training must address these issues, and be provided faster and at lower cost. Traditional classroom courses need to be reconsidered in the light of these requirements and of the development of new technologies, as far as computing and pedagogical aspects are concerned. Furthermore, Total has developed a personalized internal apprenticeship and a training path, supported all along the career, which combines technical and personal development. The search for fit-for-purpose new ways of training leads us to promote: - Distance learning studios to share specialists’ know-‐how (e.g. distant coaching from our Headquarters Training rooms), - Course capturing and broadcasting to build on experts’ experience (e.g. preserving the knowledge of departing seniors), - New in-‐the-‐field geosciences pedagogy with interactive tools (e.g. richmedia resources to enrich courses on the field), - Immersive training techniques to become operational more quickly (e.g. interactive drilling rig) - Fast learning modules (e.g. e-‐learning) monitored on in-‐house training platform. In other words we are experiencing a revolution in training content and training media. The learning process is based more and more on “real life” situations and modular courses to gain in flexibility. The presentation gives detailed and practical examples of these new tools that are targeted towards our geosciences technical staff worldwide.
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Implementation of Interval Velocity Data in the Analysis of Vertical Fluid Migration Routes and Charging Offshore Qatar
Authors K.J. Andresen, A. Uldall, M. Hertle, L. Madsen, C. Perrin, N. Rameil, G. Durance, H. Tirsgaard, M. Emang and T. GagigiOil production from the Al Shaheen Field in Block 5 and Block 5 Extension, offshore Qatar, relies on horizontal drilling and careful stimulation of the very thin and low-permeable Cretaceous carbonate reservoirs. Although the field has been in production since 1994 some uncertainties remain, particularly concerning fluid migration routes and charging of the field. The field appears to be effected by vertical anomalies which have the potential to act as vertical migration paths for fluid migration possibly impacting fluid distribution and characteristics at present day reservoir levels. This study uses 3D seismic data combined with a calculated interval velocity volume to analyse the vertical anomalies in more detail. The anomalies are vertically extensive and typically characterized by lower velocities than the surrounding strata. They have been mapped according to their vertical extent, average velocity, any associated lateral effects, initiation and termination levels and their relation to other features in the area. The results of the mapping suggest that the majority of the velocity anomalies are related to fluid migration with gas causing the anomalous low velocities. The present day gas cap in the Kharaib reservoir may have formed due to vertical migration of gas along the velocity anomalies, which in the area of the gas cap are associated with very low velocities and all terminate at the level of the reservoir. In the areas north of the gas cap, the velocity anomalies generally terminate shallower suggesting that fluid venting probably continued to the seafloor thereby preventing gas accumulation in the reservoirs. The study successfully implements velocity data in the analysis of fluid migration routes and supplements the current understanding of some of the uncertainties related to the Al Shaheen Field. The results represent new inputs to the characterisation of fluid migration within the reservoirs and the existing production and may furthermore provide new input in the assessment of the future development of the field.
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Automatic High-Throughput Detection of Fluid Inclusions in Thin-Section Images using a Novel Algorithm
Authors M.V. Bennetzen, X. Marquez and K. MogensenDetection and examination of fluid inclusions can lead to insight into diagenesis and history of a hydrocarbon reservoir. Currently, geologists are faced with a large collection of digital images, making manual investigation highly inefficient and time-consuming. A combination of data acquisition by simple and robust light microscopy and an advanced downstream computational solution is ideal with respect to cost efficiency and stable large-scale and high-throughput ability. Moreover, a strict deterministic algorithm for automatic fluid inclusion detection is not subjected to any human biases that would otherwise violate detection consistency. A novel algorithm for fluid inclusion detection has been developed and implemented in the statistical scripting language R and the object-oriented programming language C# under the .NET 4.0 computational framework. The algorithm is a result of thorough understanding of the image representation of fluid inclusions and optimized based on empirical correlations. It is based on sequential image section-specific intensity-centric selection criteria, intensity distribution discrimination and conditional statistics. Moreover, a multi-dimensional scoring-scheme has been developed and implemented. The software was able to successfully identify a series of fluid inclusions on the same thin-section image containing hydrocarbon and aqueous phases, respectively. Due to the modular structure the software is highly flexible and can be tailor-made to specific analytical needs, such as selective identification of solid phases.
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In-situ Heat Generation for Near Wellbore Asphaltene and Wax Remediation
Authors S. Tiwari, S. Kumar Verma, R. Karthik, A. Kumar Singh, S. Kumar, M. Kumar Singh and M. Dutt KothiyalOrganic deposits such as paraffin and asphaltene in the near-wellbore region are common damage mechanisms in oil wells, especially in brown fields, and account for major production losses from these fields. Typical efforts to mitigate these problems include pumping of several types of remedial treatments to inhibit or dissolve deposits, pump heated fluids as in hot oil treatments, or use mechanical methods such as cleanouts with jointed pipes and coiled tubing. Most of these methods are not time and cost-efficient for two reasons. First, such treatments are usually not one-time solutions but are required at periodic intervals depending on the severity of the problem. Second, the specific requirements such as long soaking time, exotic chemical systems, large equipment footprints, safety etc., often add to the associated service costs. In some of the fields being developed in the western onshore fields of India, heavy organic deposition across screens and in the near-wellbore region is being experienced. This is suspected to be occurring due to wax appearance temperature being close to the reservoir temperature. The wax dissolution temperature is well above the reservoir temperature, due to which any effective remedial treatment necessitates higher temperature generation for dissolution/inhibition of wax problems. Different types of solvents have been used for remediation purposes and have yielded mixed result. The concept of heat generation by exothermic chemical reactions has also been applied in the field after taking a cue from oil industry application, pipeline pigging industry to tackle the similar problems. On lines of this concept, the authors designed an effective and cost-efficient in-situ heat generation treatment to be applied in oil wells for removal of organic deposits. After laboratory testing using a range of products, the regulated components from the pipeline systems were replaced with safer, non-regulated products to suit oil well treatment. A successful field trial was achieved with the chemicals in generating heat to attain temperatures beyond the wax dissolution temperature, resulting in increased production. This paper documents the steps in developing this system and using it in the field, and aims to describe the challenges encountered, lessons learnt and recommendations for future application of the system.
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Design, Implementation and Results of an Inter-well Chemical Water Tracers Pilot Test to Improve Water Flood in Complex Reservoirs
Authors . Cuauro, F. Frans, D. Knowles, P. Wigley, C. de Mas, K. Jevanord and A.B. Al-SadahThe use of water tracers to better understand and improve water flood performance has long been part of the reservoir management toolbox. Its use is even more relevant when applied to complex and heterogeneous reservoirs. This paper describes the planning and implementation phases of a chemical tracer injection pilot in the Al Shaheen oil field, offshore Qatar. In Al Shaheen injection water has historically been used as natural tracer to identify inter-well communication in the field by analysis of the salt and ionic content of produced water. However, this approach has become less effective over time. Identification of short-circuits is getting more complex with the increasing number of wells completed. A tracer pilot including chemical water tracers was designed to identify inter-well communication and flow paths of injected water in a complex area of the field. The geology of this area is highly heterogeneous, with a stacked sequence of carbonate and clastic reservoirs. Numerous features were identified as the possible cause of these inter-well communication paths, including faults and fractures, thief zones, permeable shale and/or absence of shale. The pilot includes two water injection wells completed in two different reservoirs and twenty six oil production wells. This paper reviews the selection of the candidate wells, the operational constraints as well as the detailed analysis and interpretation of the results. Based on this pilot, interwell connection has been proven in most of the area of interest. Tracers have been detected in six of the twenty six wells, with breakthrough times ranging from three to seventy days. Communication between the carbonate and clastic reservoirs was confirmed in two wells. For some of the early samples, anomalous results were obtained. This has been attributed to contamination during sampling at the platform, and was remediated by improving the quality control during sampling. This water tracer pilot paves the way for further application across the field. Ultimately the tracer results will be used in combination with other surveillance techniques to identify by-passed oil and design fitfor-purpose solutions to target higher recovery.
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The Challenges of Extending the Life of UK Offshore Installations
Authors J. Russell and I. KeithThe majority of the oil and gas production infrastructure in the UK sector of the North Sea was installed in the 1980’s and 1990’s. Typically these installations were designed with a lifespan of 15-25 years, and many of them are now at or beyond their original design life. With higher prevailing oil prices, and continued development via subsea field tie-backs, the economic lifespan of these installations look set to exceed design lives by a considerable margin. In addition, many installations are now processing very different fluids and rates as they enter the mature phases of production. This paper describes in more detail how the life extension challenge is being managed in Shell UK. It covers the overall process being adopted for managing facilities beyond their design life, as well as describing some of the methods and techniques being used to make key decisions. The key learning’s that can be applied in other mature fields includes:
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Managing Risk in a Thermal Oil Sands Development Project Through Appropriate Technical and Well Operating Design
By M. ZatkaOil sands bitumen deposits in western Canada represent the third largest hydrocarbon resource in the world and with most requiring in-situ recovery technology, the safe and environmentally-responsible development of this resource is a key opportunity for Canada and the energy industry. Shell Canada Energy has operated thermal wells in Alberta for over 50 years in a number of different, steam- or other energy-based, recovery projects. Facing an ever-increasing regulatory demand for thermal wells that will provide safe long-term operation and stable hydraulic isolation from the thermal zone after abandonment, while meeting Shell’s operating principles in protecting groundwater and air and a minimized surface footprint, the technical demands to achieve this continue to grow. The key to overall technical success and reliable well integrity has been a systematic understanding of the parameters that lead to an appropriate and safe casing design, despite the need to operate the well casing at above-yield conditions. Through a combination of controlled materials testing, evaluation of full-scale connection behaviour under dynamic live conditions, and well monitoring during the operating phase, Shell Canada has been able to develop a comprehensive knowledge base over the past years that has enabled it to achieve a near-zero well failure rate. This has been complemented by a comprehensive well integrity monitoring program that not only allows periodic confirmation of mechanical integrity of well components, but also detection of inter-well formation anomalies that may lead to well failure or loss of hydraulic isolation if left unidentified. The know-how will be leveraged in the Carmon Creek thermal development project which is currently in detailed engineering design and, if approved, will start with two back-to-back development phases, each with a nominal target oil production rate of 40,000BPD.
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Predicting Lithology And Porosity Of Carbonate Reservoirs Using Geostatistical Stochastic Pre-stack Inversion For Geomodeling Constraint
Authors L.R. Pernia Soto, J.L. Piazza, D. Chenot and C. De MargonThis paper describes a methodology to characterize lithology variations impacting the porosity distribution in a carbonate reservoir. We performed a stochastic seismic inversion to obtain multiple realizations of elastic properties discriminating between the target lithologies. These multi-realizations were then used in a supervised lithoseismic classification for obtaining cubes of occurrence probability of lithologies. Finally, a pseudo porosity cube is obtained using a linear combination between the acoustic impedance and the lithology probabilities. The entire workflow is performed in a stratigraphic grid layering-consistent with geomodeling grid. Such capability is important for further use of the results as 3D constraint during the geomodel infilling. Lithology probability cubes show proportions in agreement with vertical facies proportions observed from well data.
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Overcoming Hydraulic Fracturing Challenges in High Temperature and Tight Gas Reservoirs of Saudi Arabia with an Enhanced Fracturing Fluids System
Authors S.M. Al-Driweesh, A.A. Dashash, A.R. Malik, J. Leal, E. Soriano and A. LopezHydraulic fracturing has been an important aspect on the successful exploitation of gas sandstone formations in Saudi Arabia. During the past decade, conventional formations were stimulated successfully with traditional low to moderate temperature borate crosslinked based fracturing fluids. As the development of the existing fields continue into deeper formations and the exploration activities are inclined toward unconventional reservoirs, new challenges are experienced from lower permeabilities and higher temperatures. The conventional borate crosslinked gels are no longer the choice of fracturing fluids for extreme bottom-hole conditions. To overcome these challenges, an improved, salt-compatible, low-polymer, organometallic crosslinked-gel (CMHPG) as fracturing fluid has been introduced for high-temperature (HT) wells. The novel HT fluid provides excellent proppant transport capabilities at temperatures ranging from 60 to 375 °F, while using fracture fluid requires less base polymer that results in less formation damage and higher retained conductivity of the propped fracture. This property is especially valuable in low-permeability reservoirs, where extended fracture lengths are typically required to maximize reservoir contact and enhance production. Additionally this fluid has been enhanced with a microemulsion surfactant to obtain a higher load recovery and also a novel clay stabilizer specially designed for tight gas and shale formations. This paper addresses the successful application of this enhanced fracturing fluid in HT and tight gas wells of Saudi Arabia along with its post-treatment evaluation comparing dimensionless productivity index between fracture treatments with new and conventional fracturing fluids.
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Quantifying the Impact of Natural Fractures and Pore Structure on NMR Measurements in Multiple-Porosity Systems
Authors L. Chi and Z. HeidariThis paper quantitatively evaluates the hierarchical structure of multiple-porosity systems, including natural micro-fractures, inter-granular, and intra-granular pores, using nuclear magnetic resonance (NMR) measurements. Conventional well logs cannot distinguish between different pore structures. NMR measurements, although counted among the most reliable methods to measure formation porosity, has been conventionally considered as insensitive to the existence of natural fractures. Thus, the impact of natural micro-fractures on NMR measurement has rarely been investigated. We simulated NMR response in porous media using a random-walk algorithm. We randomly distributed and oriented natural micro-fractures in various porous rock matrices. We then quantified the sensitivity of NMR T2 (spin-spin relaxation time) distribution to the presence of natural fractures within (a) three-dimensional (3D) Micro-Computed Tomography (micro-CT) images of carbonate and sandstone rock samples and (b) synthetic organic shale matrices. Results from synthetic rock samples showed that NMR T2 distribution can be significantly affected by aperture, concentration, and shape (e.g., needle-like or planar shape) of natural fractures, as well as size and connectivity of inter-granular pores. We also quantified the impact of diffusional coupling effect between the micro-fractures and inter-granular pores on NMR T2 distribution. Applications of this research include reliable reservoir characterization in challenging multiple-porosity systems such as naturally fractured carbonates and organic-rich source rocks, where (a) conventional well logs cannot reliably characterize the complex pore structure and (b) interpretation techniques for unconventional logs such as NMR are not fully developed.
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The Emerging Potential of Re-Os Isotope Geochemistry for Source Rocks and Maturation-Migration Histories
Authors H.J. Stein and J.L. HannahJust a few years ago, the petroleum industry relied almost solely on lithostratigraphy, biostratigraphy, and U-Pb dating of volcanic tuffs and flows for correlations across basins in the sedimentary record. Re-Os technology was first applied to synsedimentary pyrite to obtain depositional ages for sedimentary rocks. Subsequently, organic-rich shales with their anomalous metal contents became the target for direct dating of source rock deposition. If organic material extracted from a source rock provides depositional ages, so too should the creation of new hydrocarbon be datable. Precise dating of organic-rich shales using Re-Os has immediate applications for hydrocarbon exploration by placing time pins at intervals of earth crises marked by anoxia and euxinia. These are the events that create rich source rock. In addition, unlike other geochronometers, Re-Os isochron ages carry key information on environmental conditions during source rock deposition through trace metal concentrations, stable isotope compositions, and the Os initial ratio. Trace metal abundances reflect the extent of anoxia and sedimentation rates, both of which impact concentration and preservation of organic material. Stable isotope compositions reflect the type of organic material. The Os initial ratio is a powerful proxy for marine and lacustrine conditions during shale deposition – for example: What was eroding and how fast? What are the depositional rates for accumulation of organic-rich material? What kinds of fluids were present and mixing in a basin and for how long? The nuances derived from this kind of information are far-reaching. For shales at maturation, with some or all of the generated hydrocarbons still residing in the shale (unconventional hydrocarbon), the timing of maturation can be teased from the Re-Os data. For conventional migrated hydrocarbon, good scientific interpretation requires the creativity to analyze players along migration paths before the reservoir is reached. We will present an accessible and understandable overview of Re-Os geochemistry and geochronology in the context of case studies. The field is new and the potential is enormous for petroleum exploration.
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Malaysia Deepwater Development: Optimizing the Reservoir Management in a Changing Environment
Authors R. Masoudi, H. Karkooti, K.S. Chan, M.B. Othman, S. Burford, M. Sarginson, V. Till, P. Bee and D. CheneryDeep water fields are subject to higher development costs than more conventional field developments and often have challenging topside and subsurface issues and uncertainties. The level of heterogeneity, compartmentalization, fault intensity, reservoir connectivity, pressure and flow communication across the field, sand/fine production, wellbore stability are commonly less understood at the time the development decision is made. The reservoirs may also consist of very thin beds (cm thick) to thick blocky sands and the reservoir properties / connectivity can vary significantly both laterally and vertically throughout the field. This paper describes a deepwater case study offshore Malaysia, and in particular the challenges of optimizing deepwater Reservoir Management / development in a changing development environment. As a result of some early well failures and associated sand production, TesTrak© pressure data acquired during re-drilling some of the wells has provided an invaluable insight into the complexities of deepwater reservoir development and thin vs thick bed recovery efficiencies. This has led to further development optimization such as the deployment of SMART water injection completions and dedicated thin bed high angle wells as required to solve specific by-passed oil targets. In this paper, the above challenges and reservoir management (RMP) requirements combined with the concerns of the optimized water flooding in a complex deep water field in Malaysia have been studied and discussed.
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Permeability Prediction Using Probabilistic Neural Network (PNN): Application to the Paleozoic Shallow Marine Sandstone of Quwarah Member, Qasim Formation, Saudi Arabia
Authors O. Abdullatif and M. ShuaibThis outcrop analog study was conducted on surface equivalent to the Quwarah member of the middle to late Ordovician of Qasim Formation in central Saudi Arabia. The Paleozoic section contains important oil and gas reservoirs with more to explored and developed mainly related to unconventional tight gas and shale gas. The main objectives of this work is to use the probabilistic Neural network (PNN) to predict permeability of the Quwarah sandstone on the basis of systematically collected and petrographically estimated textural and compositional data from the outcrop sections of the Quwarah member. The results show that probabilistic neural network (PNN) was capable of reproducing permeability with very high accuracy, so that the calculated correlation coefficient for permeability was 0.89. This outcrop analog study, when integrated with subsurface data, might provide database, reveals heterogeneity and enhances understanding and better prediction of reservoir quality in the subsurface.
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Pore-Scale Imaging of Oil and Wettability in Native-State, Mixed-Wet Reservoir Carbonates
Authors N. Dodd, R. Marathe, J. Middleton, A. Fogden, A. Carnerup, M. Knackstedt, K. Mogensen, X. Marquez, S. Frank, N. Bounoua and R. Noman3D pore-scale imaging and analysis provides an understanding of microscopic displacement processes and potentially a new set of predictive modeling tools for estimating multiphase flow properties of core material. Reconciliation and integration of the data derived from these models requires accurate characterization of the pore-scale distribution of fluids and a more detailed understanding of the role of wettability in oil recovery. The current study reports experimental imaging progress in these endeavors for a preserved-state carbonate core from a Middle Eastern waterflooded reservoir. Micro-CT methods were used in combination with novel fluid X-ray contrasting techniques and image registration to visualize the 3D pore-scale distribution of residual oil in mini-plugs. Segmentation of the registered tomograms and their differences facilitated estimation of the residual oil saturation. These predictions from digital analysis agreed reasonably well with laboratory measurements of oil saturation from extraction of sister mini-plugs and spectrophotometry. The tomogram segmentations provide additional information beyond this average value, such as the fractions of oil associated with macroporosity and microporosity. After the tomogram acquisitions, one of the dried mini-plugs was cut and SEM imaged at this exposed face to provide 2D images of fine features below the micro-CT resolution limit, such as the characteristic dimpled texture of asphaltene films on calcite surfaces due to their local wettability alteration in the reservoir. A new registration procedure was developed to embed the SEM images from the cut plug into the tomogram of the original uncut plug at their correct locations, so that this high-resolution wettability information could be integrated into the 3D pore network description and correlated to the local distribution of residual oil.
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Advanced HPCT Abrasive Perforating Technique Utilized to Successfully Bypass Damaged Formation to Allow for Effective Acid Stimulation
Authors A.R. Malik, M.S. Buali, T.M. Ogundare, A.E. Mukhles, T. Green and M. HaekalThis paper will discuss how an advanced technique of abrasive perforating with high pressure coiled tubing (HPCT) was utilized to bypass damage that existed in the open hole section of the well-bore as a result of a recent descaling operation. The well discussed in this paper had extensive scale and therefore required coiled tubing (CT) intervention to clean the wellbore. Following the scale cleanout, a matrix bullhead acid job was performed to bring the well back to production. Some +nonacid soluble scale remained in the wellbore was pushed into the formation ahead of the matrix treatment. As a result, no incremental gains were achieved after the acid treatment. After analysis of the cleanout, stimulation data and results, it was determined that the cause of the now poor production was scale debris plugging the formation. As the scale was not 100% acid soluble, the team chose to use an abrasive perforating tool with HPCT to bypass the suspected damage. Fifteen stages of perforation were successfully conducted using HPCT Advanced Abrasive Perforating Technique in a single run in depleted carbonate reservoir. Following the HPCT abrasive perforating operation, good injectivity was reestablished and the well was successfully stimulated to bring the well back to optimal production.
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Diagnosis of Multiple Fracture Stimulation in Horizontal Wells by Downhole Temperature Measurements
More LessDiagnosis fractured well performance for a multiple-stage fractured horizontal well is critical to understand and improve fracture stimulation design. Production logging tools (PLT) can be used in this problem, and temperature distribution data (by PLT or fiber-optic sensors) is one of the valuable information for performance diagnosis. However, until today quantitative interpretation of dynamic temperature data is still challenging and requires indepth mathematical modeling of heat and mass transfer during production in a complex flow system. In this study we developed a semi-analytical model to predict temperature and pressure behavior in a multiplefractured horizontal well during production. The tri-linear model is used to simulate flow in a fracture system for horizontal wells. The model can be applied for single phase oil or gas wells. For gas well, the non-Darcy effects are considered by permeability alteration using minimum permeability plateau. Flow in the wellbore is modeled under unsteady state condition modified from a steady state horizontal wellbore model presented before. This coupled model for fracture flow and wellbore flow can predict the pressure gradient along fracture and also the pressure and flow rate distribution in the wellbore. The thermal model calculates the heat transfer in the fracture/reservoir/wellbore system considering subtle temperature changes caused by the Joule-Thomson cooling and frictional heating effects. The fluid properties are set as functions of in-situ pressure and temperature. The result shows that transient temperature behavior can be used to estimate the fracture initiation points and length, number of created fractures and distribution of fluid along the wellbore. The temperature is sensitive to the flow rate distribution along the wellbore, the fracture geometry, and also the fracture conductivity. With the developed method, we can evaluate the fracture treatment by comparing the designed fracture half-length with the generated fracture-length. When applied in history match of production data, it also can predict conductivity decline as a function of production time.
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Narrowing the Loop for Microporosity Quantification in Carbonate Reservoirs Using Digital Rock Physics and Other Conventional Techniques - Part II
Authors A.A. Al-Ratrout, M.Z. Kalam, J.S. Gomes, M.S. Jouini, S. Roth, H. Lemmens and B. MtawaaMicroporosity quantification is becoming increasingly important to assess the distribution of hydrocarbons and their remaining/residual saturations after water flood (and /or gas flood). Assessing uncertainties and limitations in microporosity estimations of carbonate cores, comprising different reservoir rock types have been a challenge for geoscientists. The advent of Digital Rock Physics (DRP) based measurements allow the pore 3D network images from micro and nano - Computed Tomography (CT) scans on selected sub-samples to map representative cores and Reservoir Rock Types (RRT). The DRP based microporosity is rigorously examined and compared with other techniques/tests. In Part I (Al-Ratrout, Kalam, Gomes, & Jouini, 2013) we presented conventional techniques, such as Mercury Injection Capillary Pressure (MICP), Nuclear Magnetic Resonance (NMR), Thin Section (TS) and Backscattered Scanning Electron Microscopy (BSEM) are used for semi-quantitative evaluations of microporosity. Images at different magnitudes (4X, 10X, 40X and 100X) were captured from TS and BSEM, and used to quantify porosity using image analysis software. NMR and MICP measurements acquired through a commercial laboratory were also analyzed to quantify the microporosity. DRP based 3D pore network images have been acquired at different scales of interrogation from nano to micro meters to define microporosity. In this paper we examine DRP results based on three state-ofthe- art techniques, such as Pore-Network Fusion, to combine micro and nano-CT to enhance microporosity estimations. Cutting edge nano level investigation involving Focused Ion Beam Scanning Electron Microscopy (FIB-SEM) and last technique is the 2D Large Mosaic Image using modular automated processing system (Maps). This work has shown DRP to be as excellent tool to assess microporosity, and quantify the microporosity effectively in 3D pore network. The evaluation with conventional techniques demonstrated the current industry limitations and uncertainty.
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Secondary and Tertiary Polymer Flooding in Extra-Heavy Oil: Reservoir Conditions Measurements - Performance Comparison
Authors C. Fabbri, C. Cottin, J. Jimenez, M. Nguyen, S. Hourcq, M. Bourgeois and G. HamonIn the challenging context of heavy to extra heavy oil production, polymer flood technology appears to be a promising solution to enhance ultimate recovery of reservoirs. Several field applications have already shown the efficiency of such technologies, although the final incremental recovery and mechanisms involved are still poorly understood. Indeed, the characteristics of the viscous fingering effects that certainly play a role are rarely captured at the field scale or at the core scale. This work aims at comparing the results of two core experiments with polymer flood in secondary and tertiary mode, in reservoir conditions, in term of recovery as well as in terms of relative permeabilities. In both cases, experiments were carried out on reconstituted reservoir cores, with restored wettability, initially saturated with live oil partially degassed in a PVT cell to the expected pressure and viscosity at the start of the field test. Saturation profiles were measured with X-Ray scans; effluents were collected in test-tubes and analyzed by UV measurements. Additional follow-up with tracers was tested in order to better assess the breakthrough of different fluids as well as the polymer adsorption during the experiment. Although the viscosity ratio was still highly unfavorable, with a polymer bulk viscosity around 70 cP at 10s-1 and an oil viscosity estimated at 5500 cP, polymer floods exhibit an excellent recovery factor.
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Imaging The Pre-khuff: Changing The Game With Innovative Seismic Technology
Authors M. van der Molen, C. Harvey, M. Molinaro, R. Navarro-Luna and P. StigborgThis paper describes how QSUI was able to overcome some of the significant geophysical challenges associated with Pre-Khuff exploration. On legacy seismic data, strong multiples from the layered carbonate overburden overwhelm the relatively weak primary reflections from the deep Pre-Khuff clastics. In order to identify and understand the main generators of coherent seismic noise, Qatar Shell Upstream International (QSUI) has undertaken seismic modeling using VSP data, legacy shot records and full-waveform synthetic modeling. Results of this work informed the reprocessing of existing seismic and the design of a 3D Ocean Bottom Cable (OBC) seismic survey. The acquisition of dual component (2C) Wide-Azimuth (WAZ) OBC data, together with state-of-the art in-house seismic processing led to a break-through in seimsic imaging of the Pre-Khuff reservoir layers. This has demonstrated that the geologic intervals below the Hercynian unconformity exhibit a steeper dip compared to the overlying Khuff and younger sediments, as expected by the geologists and observed in neighboring countries.
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Utilising Integrated Natural Gas Liquids (NGL) and Nitrogen Rejection unit (NRU) technology in Qatar on the Barzan Gas Project
More LessIntegrated Natural Gas Liquids/Nitrogen Rejection Unit (NGL/NRU) technology will be utilised for the first time in Qatar on the Barzan Gas Project, which is a joint venture project between Qatar Petroleum (QP) and ExxonMobil Barzan Limited. The North Field Reservoir, which supplies the Barzan Gas Project, contains a high content of inerts, e.g., nitrogen and helium. One challenge was to identify a technology to achieve the required specifications of the sales gas by rejecting the inerts from the feed gas. RasGas initiated a study to evaluate process licensors’ capability to supply an integrated process design for recovering NGL and rejecting nitrogen for the Barzan Gas Project. The requirements are to recover the NGL product stream, containing 95% of the incoming ethane content and essentially 100 per cent of the propane and heavier (C3+) hydrocarbons. One primary component of the technology is to reject nitrogen from the gas stream to achieve an acceptable BTU content and Wobbe Index to meet QP sales gas specifications. To achieve the above requirements, Chart Energy and Chemicals Inc, as a technology licensor, demonstrated the ability to provide an integrated NGL/NRU licensed process with the following merits: • Utilises a proven Brazed Aluminum Heat Exchanger (BAHX) supplier. • Takes advantage of the available feed pressure to minimise overall energy consumption without requiring excessive Aluminum / surface area. • Utilises high efficiency compression to meet final sales gas delivery requirements. • Minimises footprint and plant congestion by installing equipment within sealed cold boxes. • Provides a simple exchanger arrangement for easy conversion to various modes of operation.
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A Hurt-Based Approach to Safety
Authors R.M. Smith and M.L. JonesThis paper describes the Hurt-based Approach to Safety that ExxonMobil’s Upstream Companies use in personnel safety management. Traditionally, ExxonMobil has primarily used industry standards driven by the U.S. Occupational Safety and Health Administration (OSHA) to classify safety events based on the treatment and/or restrictions provided. However, this treatment-based approach has limitations. With intense focus on administrative reporting (i.e., is the incident recordable or not?) and incident escalation management, the approach does not naturally resonate with workforce members to enable desired cultural changes. Also, historical approaches have not included a potential consequence assessment; a critical element in preventing future injuries. Incident classifications are often inconsistent because work restrictions and medical treatments are subject to individual medical provider judgment. ExxonMobil has created a Hurt-based Approach to mitigate limitations of the treatment-based approach. This paper discusses the history of ExxonMobil’s “Hurt Free” philosophy and explores benefits: natural safety language of humans; protect family, prevent injuries consistent description of actual injury severity integral assessment of potential injury severity resonates with workforce to enable cultural changes based on caring for people alignment with Exxon Mobil Corporation’s safety vision of “Nobody Gets Hurt” These benefits, along with passionate safety leadership and Hurt-based metrics, are critical elements in ExxonMobil Upstream’s safety management systems. While many companies have some of these elements in their programs, it is the combination of all elements that drive ExxonMobil’s Hurt-based Approach. This paper will share ExxonMobil’s expectations of safety leaders and insight into how a Hurt Free philosophy leads to higher levels of understanding and promotes safety leadership throughout the organization. It will describe how a Hurt-based Approach provides a more natural line of sight for assessing incident potential and provides a more natural and caring interaction with injured parties; thereby, creating a more positive personal safety culture. It will describe how potential consequence is determined and how this potential drives the prioritization of resources, incident assessments, work activity focus, etc. It will detail ExxonMobil’s “Mining-the-Diamond” initiative which provides increased focus on high consequence potential work activities that could result in life-altering injuries or death. Trend analysis will be provided to illustrate continuous improvement efforts.
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Establishing Higher Oil Production Capabilities: Engineered Approach Achieves Longest Lateral Hole Section in Kuwait
Authors H. Al-Ajmi, N. Al-Barazi, A.-A. Al-Rushoud, R. Trivedi, H. Maliekkal, O. Ghoneim, M. Saleh and P. NairKuwait Oil Company (KOC) is analyzing the feasibility of utilizing extended reach drilling to achieve a long lateral section to increase oil production in northern Kuwait. Several attempts were made to accomplish the objective with roller cone and PDC bits on various directional tools with limited success. The major problem was short bit life/cutting structure durability and steerability issues in the difficult Mauddud carbonate reservoir. A drilling optimization initiative would benefit the entire northern Arabian basin because Mauddud is an important oil reservoir with uniform thickness and extensive regional distribution. Offset analysis showed three to four TCI bits were required to drill 3000 ft of lateral hole section. PDC bits display increased durability making up to 2500 ft of hole but were pulled for low ROP and unacceptable drilling inefficiency before reaching TD. A second PDC was required to finish the lateral and gain sufficient access to the reservoir. Before the optimization project, the longest single run with PDC was 2935 ft. The average footage drilled by roller cone TCI is approximately 1500 ft with average PDC footage around 2500 ft. To improve PDC bit performance, a rock strength program was run to identify the unconfined compressive strength (UCS) of Mauddud for use in an FEA-based modeling system. The software pegged the formation’s UCS range between 9-15 kpsi with peaks up to 24 kpsi. Analogous rock sample files were selected and laboratory tests were performed to duplicate fundamental shearing action under the appropriate confining pressures. The resulting data was entered into the modeling system and simulations were performed with a baseline PDC to identify how lithology influences the bit/BHA and to investigate was to mitigate destructive drillstring dynamics. The engineering study produced a six-bladed PDC that drilled the longest lateral interval (5250 ft) in Kuwait through Mauddud. The bit displayed excellent steerability and completed the hole section without losing ROP. This resulted in 100% footage improvement against offset PDC runs and is more than 150% better than the best TCI performance. The completed well has provided a 200% increase in production capabilities making up to 4500 bbls/day.
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A Dynamic Imaging Particle Analysis System for Real-Time Analysis of Drilling Muds
Authors L. Brown, M. Duplisea and S. BowenThis paper details a novel new system for real-time analysis of drilling muds. The system uses in-flow digital imaging to capture images of all particulates in drilling mud. Sophisticated image processing algorithms are used in real time to segment each particle from the background, and record over 30 size, shape and gray-scale measurements for each particle. Particle size and shape distributions are produced in real-time, and are used for trend analysis. This system can be integrated into any part of the drilling flow loop for analysis at any point in the process. Using a unique auto-dilution system, the concentration is automatically adjusted for optimum presentation of the particulates to the imaging system. Since every particle image and its measurements are saved by the system, it creates an ironclad audit trail for how particle size distributions are derived. While the basic system architecture is very robust and could be used in many different applications, the system presented here has been fully optimized for the analysis of particulates in drilling mud. Real-world data collected in the field is shown illustrating typical results from the system. A brief description is provided on how the system works in real-time, including how the particle images are acquired and measurements made. Finally the results of the analysis are shown, detailing how the system can be used to monitor particle size and shape distributions from any part of the flow loop. This resulting analytical data becomes an integral part of the real-time operation of the drilling platform, ensuring continuous optimization of the drilling mud particulate content. This optimization is critical to the performance of the drilling mud, for cooling and lubrication of the drill bit, interacting with the surrounding geology and maintaining proper rheological characteristics. This system represents a new way of proactively monitoring drilling mud content in real-time, and provides more information than prior systems because the system can measure particle size as well as shape. Particle shape information can be used by the system software to automatically classify particulates into different component types.
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Approximations of Primary, Secondary and Tertiary Recovery Factor in Viscous and Heavy Oil Reservoirs
Authors R. Kaczmarczyk, J. Herbas and J. Del CastilloLimitations in the availability of methods to estimate recovery factor at the initial stage of petroleum exploration pushes for investigation new ways of analysing available datasets. This work investigates empirical and volumetric methods to estimate recovery factors in viscous and heavy oil reservoirs. It also investigates newly available advance screening methodology to determine tertiary/ultimate recovery factor in these reservoirs. Initially, primary recovery factor was estimated based on field analogy. Secondary recovery factor was calculated using empirical equations. In the second, main part of this work, ultimate recovery factor was approximated using data mining/machine learning approach to reveal eventual trends in viscous or heavy oil databases. Information contained within this project was used to estimate recovery factors in certain viscous oil reservoirs at the initial stage of exploration. However, after reformatting original data base, advance screening methodology would be potentially applicable to any viscous or heavy oil reservoir around the world. It was found during the project that the primary recovery factor can be successfully estimated based on the field analogy. Empirical methods can be applied in some cases. The quality of the obtained results depends on whether they were derived for conventional or heavy oil reservoirs. Based on advance screening, it was shown that tertiary/ultimate recovery factor can be successfully estimated. Final product includes development of a methodology on how to approach the recovery factor approximation in viscous or heavy oil reservoirs without production history or at early stage of the field life.
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Drill Pipe Connection Technology Enables Saudi Aramco & Precision Drilling to Deliver the Longest Horizontal Well in Saudi Arabia
Authors A. Iravani, M. Hanafi, S. Al-Shehry, G. Plessis and N. MohamedRecently in Saudi Arabia, a national drilling record was reached for the longest horizontal well drilled. A key technology for drilling such wells, which typically show a Total Depth (TD) in excess of 30,000 ft, was the use of extended reach horizontal drilling. Drilling these wells required, among other things, a proper selection of drill stem products. With drill pipe accounting for most of the string length, choosing the right specification plays a huge role in overall drilling performance. With a lot of friction as the string is ran downhole, the ability to transmit torque to the bit is challenging and connection technology becomes critically important. Double shoulder connections place connections at par with the pipe body in terms of torque capacity and actually come with additional benefits. Not only do these connections transmit higher torque but they do it using a thinner steel envelop, which allows a larger internal opening for improved hydraulics. Furthermore, these streamlined connections can also come with reduced Outside Diameter (OD) tool joints which help keep the Equivalent Circulation Density (ECD) as low as necessary to maintain formation integrity. Towards the end of 2010, a national record 32,136 ft measured depth well was drilled in Saudi Arabia using such connection technology, proper material grade selection and optimized pipe size selection. The well was then used for horizontal water injection into the reservoir in order to maintain reservoir pressure and optimize production. This paper will describe the challenges of this project and how connection technology, engineered material grade and pipe size helped address each of these challenges. The record well case history will form the base of this paper and authors will include a comprehensive section on the successfully selected connection, its performances as well as a summary of more recent results.
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Long Term Wellbore Isolation In a Corrosive Environment
Authors O.R. Ilesanmi, B. Hilal, S. Gill, A. Brandl, M. Al Mazrouei and A. AbdullahThe paper reviews two case histories about successful wellbore isolation with a suitable cementing system for a recent enhanced oil recovery / CO2 project targeting the Thamama B formation of the Bab Far North reservoir in the UAE. The first two wells were vertical observers with zonal isolation required between the Thamama A and B. These wells were expected to exhibit a naturally corrosive environment (e.g. 56,000 ppm of CO2). To address these challenges, a fit-for-purpose cementing system, suitable for CO2 and other corrosive fluids, was developed and successfully applied. The system was designed to isolate and protect specific Thamama zones and wellbore areas that contained gaseous or liquid corrosive CO2. This cement slurry was developed with a density of 16.7 ppg exhibiting expanding properties after setting to compensate potential shrinkage issues and to improve cement bond. Laboratory test results for the developed cementing system, such as compressive strength development, thickening time, expanding properties after setting, and integrity after long term exposure towards wet CO2, are presented and discussed. Performance requirements for cementing sytems to qualify for CO2 tolerance are elucidated. Finally, the execution in the field and the quality of the cement job was evaluated. All of the special designs exhibited excellent bond log results. The favorable lab test results and the positive case history conclude that the developed cementing system can be a viable solution to provide long term zonal isolation in a wellbore with a corrosive environment.
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