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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
201 - 300 of 354 results
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Systematic Evaluation of Asphaltene Formation Damage of Reservoir Fluids from Lake Maracaibo, Venezuela
Authors A. Memon, C. Borman, M. Garcia, D.J. Reyes Tristancho, J. Ratulowski and J. GaoOne of the most concerning areas for asphaltene deposition is the near-wellbore region, where such deposition causes formation damage. The reservoir fluid of the Lake Maracaibo region is known to experience operational problems due to asphaltene deposition inducing production losses. A detailed asphaltene formation damage investigation was performed on the live oil samples from the Lake Maracaibo area. An unusual asphaltene precipitation envelop was observed for this fluid and reported in an earlier publication (Gonzales et al., SPE 153602, 2012). In the current paper, we focus on the systematic evaluation of asphaltene formation damage using stacked composite core samples. A special coreflood system was designed for an asphaltene formation damage study using reservoir core samples and sour–live reservoir fluid samples. The effect of flocculated asphaltene in the porous media was evaluated as the reservoir pressure decreases below the asphaltene onset pressure (AOP). Live samples were collected and flooded through the stacked composite core plugs under reservoir conditions. Progressive pressure reductions were performed to induce asphaltene precipitation in the porous media. Oil permeability changes were measured to evaluate the effect of this phenomenon in the reservoir using composite core. Significant impairment of composite core was caused by the depressurization of the reservoir fluid below AOP. The inlet pressures of the composite core stack were maintained just above AOP and the outlet pressure approximately 50 psi above saturation pressure throughout the core flood experiment. Thus, asphaltene precipitation onset occurred inside the composite core. This experiment showed significant permeability loss in the composite core after sufficient flooding of live oil fluid. Following the core flood experiment, the core stack was depressurized, and the remaining hydrocarbon was extracted from individual core plugs. Detailed chemical analyses were performed on the extracted hydrocarbon deposits from individual core plug with various analytical techniques, such as asphaltene content, simulated distillation, optical density, and thin-section analysis. These analyses’ results confirmed that the observed oil permeability loss was indeed due to the formation of asphaltene deposit inside the porous media, and the asphaltene deposition was somewhat more extensive in the tighter core sections.
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The Field Tests for Measurement of Downhole Weight on Bit (DWOB) and the Calibration of a Real-time DWOB Model
Authors G. Hareland, A. Wu and L. LeiThe Drilling Engineering Research Group at the University of Calgary has been seeking better ways of improving drilling operations and decreasing costs by the use of advanced real-time modeling and simulation technologies. It is well known that the performance of a drill bit directly affects the overall drilling performance. The bit performance is often evaluated by the rate of penetration (ROP) which is dependent on the weight on bit (WOB). Therefore, obtaining actual downhole weight on bit (DWOB) is crucial in achieving good performance of a drill bit. This paper defines the procedures or steps to measure DWOB and an analytical model for calculating DWOB using typical surface collected drilling data. Field test data is used to initially calibrate the analytical model. The calibrated analytical model is next used in a forward calculation to predict DWOB on the same well. DWOB is also predicted on a second well using the same drilling rig. The results from the calibrated model are compared to the DWOB collected by the CoPilot, a Baker Inteq downhole measurement tool. The comparison shows that the DWOBs from the model match those from the CoPilot well. The model can be integrated in a new directional Autodriller system, which can in real time set the DWOB from surface measurements. The directional Autodriller can automatically conduct real-time analysis and calculations of DWOB as well as maintaining a precise DWOB for the drill bit. This will improve drilling efficiency and reduce cost.
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Dukhan Field CO2 Injection EOR Pilot: Reservoir Modeling & Planning
Authors O. Ozen, T.A. Wahlheim, T. Attia, L. Barrios, M.N. Bin Ab Majid and J. WilkinsonA reservoir study was conducted to plan a near-miscible CO2 gas injection pilot in the Dukhan Field with the following study guidelines: • Determine overall objectives and timeframe for the pilot • Design the pilot to meet the objectives and timeframe • Plan the pilot in a portion of the field with representative reservoir description • Propose a surveillance and monitoring plan to ensure high quality information is obtained for interpreting the pilot performance • Design the pilot so the recovery processes are scalable to larger well spacing for reservoir-wide application Using these guidelines, the following pilot objectives were developed: • Provide data on well injectivity and productivity • Reduce uncertainty in the estimation of incremental oil recovery from CO2 gas injection relative to waterflood • Provide data to allow commercial scale well and facility CO2 gas injection design • Minimize the impact on current operations outside the pilot area. The results of the reservoir modeling study provided the detail for well orientation and placement to satisfy the pilot objectives at a reasonable cost and within appropriate timeframe for information gathering, analysis, and commercialization decisions. The reservoir model pilot area selected is one kilometer square segment in a crestal structural location that does not contain active wells and is near existing surface facilities. The reservoir description data used for the segment models were extracted from history matched full-field reservoir models. The proposed pilot wells are located within close proximity of each other to achieve gas breakthrough and oil bank arrival within the proposed pilot evaluation period of two years. The pilot design ensures that the pilot would allow for data gathering of key project design information; such as injectivity, gas breakthrough timing, oil displacement, and reservoir sweep.
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Karachaganak Brownfield Vs. Kashagan Greenfield: Analogues Or "Apples And Oranges"?
Authors C. Albertini, L. Bado, F. Bigoni, A. Francesconi, K. Imagambetov, G. Leoni and V. TarantiniCan Karachaganak field, in production since 1984, represent a good analogue for Kashagan field which is approaching the production start-up? In fact the two carbonate buildups developed in the same geological context, the Pre-Caspian-Basin margins, during the same stratigraphic interval, Visean-Bashkirian. While their depositional facies are comparable, their internal architecture, as inferred from seismic, is different. Karachaganak, affected in its early stage by tectonic, developed initially with aggrading mound complexes followed by prograding clinoforms; it is characterized by biohermal deposits passing, in its upper part, to cyclic, grain-dominated platform interior sediments. Kashagan started developing with a retrograding pattern followed by prograding and then aggrading patterns; it is characterized by a large platform interior, made of grain-dominated cyclic deposits, surrounded by a narrow biohermal rim and slope. The diagenetic overprint consists of marine cementation, dolomitization and later dissolution in Karachaganak while, in Kashagan, an early diagenesis, dominated by cyclic subaerial exposures and karst was followed by late burial cementation. The resulting reservoir qualities reflect these different geological backgrounds. Karachaganak, quite heterogeneous, is dominated by microbial boundstone, in situ and breccias; it shows low porosity but locally high productivity when affected by micro-fractures and vugs. These characteristics are consistent with the wide range of well performances historically observed (orange!). Kashagan instead appears dominated by two rock types: platform cyclic grainy porous rock, having moderate productivity and cemented poor rim boundstones affected by outstanding productivity because of the presence of both karst and solution-enlarged fractures. These data support the expected bi-modal performances (apple!).
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Pushing Maximum Reservoir Contact Applications to New Limits in Tight Facies: A Case Study of Middle East's Highest Reservoir Exposure Producer
Authors M.A. Suwailem, M.A. Zarea, R.F. Saleh, C.X. Verma and H.A. NooruddinThe paper presents the evolution of reservoir management strategies that supported a recently drilled penta-lateral producer, which set a company record of total reservoir contact in a major greenfield in the Middle East. This paper will investigate the maximum reservoir contact (MRC) evolution in the field, the design phase of this game-changing producer, lessons learned and future implications. The reservoir management objective for this producer was to capture oil reserves in tight layers (less than 10 md) in a gas cap driven carbonate reservoir while delaying gas breakthrough. This design was employed to push the MRC application to new limits of more than 16 kilometers to deliver more production at reduced well requirements while honoring best-in-class reservoir management practices. In the design phase, a very high resolution reservoir simulation model was used to model the performance of this producer. Several sensitivity cases were conducted testing various well designs in terms of lateral spacing and completion depths. Subsequently, this producer was drilled with smallest lateral spacing (62 meter) closer to the oil-water contact (OWC). The drilling of five laterals in 6 ⅛” slimhole was a challenging task that posed hole cleaning threats across the horizontal sections and risked tight hole turning to stuck pipe. Through careful planning and team collaboration between various departments, the well was completed successfully with minor problems. In addition, the well was completed with two permanent downhole monitoring system (PDHMS) gauges and inflow control valves (ICVs) to manage water/gas movement and to ensure lateral clean-up.
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Gas-Oil Ratio (GOR) Estimation Utilizing Downhole Well Sensors
Authors H. Al Muailu, F. Al Khalewi, H. Fallatah and A. Al FakherAs the concept of intelligent fields mature, field operators expand on the installation and utilization of downhole instrumentation in a quest for higher oil and gas recovery and net present value. Permanent downhole monitoring systems (PDHMS) are some of the intelligent field implementation enablers, which provide continuous monitoring and surveillance of wellbore/reservoir performance in addition to their recognized operational safety enhancement through elimination of well intervention operations for data acquisition. The advanced analysis of the data provided by this equipment forms the key to unlocking their full utilization potential and recognizing the value of the information that they provide. A remote field located in Saudi Arabia commenced its production from a thin oil column lying between a large gas-cap and a water aquifer. The gas-cap gas breakthrough and production from the producing wells have increased gradually; resulting in an increase in the wells gas-oil ratio (GOR) from an average of 880 standard cubic ft/stock tank barrel (SCF/STB) at the start of the field production to 1,536 SCF/STB. The production of these wells is currently controlled using the surface and subsurface control valves to maintain the gas production and GOR at acceptable levels. The wells connected to rate testing facilities are delivering non-accurate gas rate measurements because of frequent malfunctioning in the Coriolis meters. This problem is being mitigated in several fronts such as replacing the testing facilities; however, a method to estimate the GOR in the wells is needed until all the old testing facilities are replaced. An innovative technique to identify the onset of gas-cap-gas production and estimate its value using the downhole sensors has been developed to provide early notification of the free gas breakthrough and improve its control. This technique can provide an estimation of the wells’ GORs and can be used as a validation method to the testing facility GOR measurements. This paper proposes an approach to estimate the GOR using Matlab code that helps in the calculation of the pressure drop between the PDHMS and matching it with the actual readings at the estimated GOR. This technique was tested on three wells with healthy rate and PDHMS information.
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Production Optimisation Maximum Reservoir Contact Well, Part III: Field Tests with Acoustic-Tolerant Multiphase Flowmeter
Authors E. Al-Alyan, S.M. Al-Mutairi, F.M. Al-Subaie, O.H. Unalmis and L.W. PerryThe energy industry continues to explore innovative technologies and measurement methods. Will completions have become even more complex today± many wells have multizone production capabilities and are equipped with advanced control devices, such as inflow control valves (ICVs). An even flow distribution can be achieved by cintrlling the zonal flow rates with the end result being more efficient production and longer lifetime of the well. One of the requirements to achieve this level of production ooptimization is to monitor the zonal multipohase flow rates in real time. Real0time zonal flow measurement downhole also helps detect production anomalies and recude the need for surface well tests and facilities. This work carries a historical perspective: it is the third poart of an ongoing effort that started in late 2007. In the first past, which was published in 2008, it was shown that the oprtical flowmeter provided invaluable information and operated successfully at most ICV settings, while for some specific ICV settings the excessive acoustic noise masked the flow signal. The findings from the first part were instrumental in improving the flowmeter desigtn to tolerate higher acousticv levels. The new design, Gen-2 System, was tested regorously under laboratory conditions along with teh earlier Gen-1 System, and a Hybrid System, which were specifically designed for already-installed equipment. The design improvements and the results of this comparative laboratory work were the subject of the second part published in early 2010. This third part now focuses on the two separate field tests with the Hybrid System, which took place in 2010.The field tests revealed important facts i three key areas: flow measurement, well operation and well optimization. The test results demonstrated that the Hybrid System is vapable of toleration acoustic levels, which were not possible with the Gen-1 System, and that the issues related to excesseive acoustics that masked the flow signal at some specific ICV settings in earlier tests have been largely eliminated. As a result the Hybrid and the superior Gen-2 Systems can now be used in close proximity to control valves. The tests also revealed the fact that the use of surface choke system plays an important role in the well operation as it affects the flow conditions downhole. Finally, based on the flow measurement tesults and all the available data, optimum ICV settings can be determined for the production mode. The work also provided insight into the collaboraiton and feedback process during the course of the field tests. The currejnt work, which represents the successful closure of an effort spanning a four-year period from 2007 to 2011, sets an eccellent model that can be used to improve other technologies in the industry: that open collaboration between the operator and the equipment manufacturer can lead to advancement of technology, and as a result, provide more rubust solutions.
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How to Manage CT Operations in Hostile Environment: Field Case Studies on CT Challenges in Deep HPHT High Sour Carbonate Formations
Authors S. Packirisamy, H. Al-Bader, Y. Al-Salali, D. Vidyasagar, A. Manimaran, A.R. Al-Ibrahim and A. RajkhowaObjective of this paper is to present our recent case-histories involving uncommon and unexpected Coiled Tubing (CT) intervention challenges in exploratory wells while testing and stimulating deep HPHT high Sour carbonate formations. Jurassic formations at around 17,000 feet in Kuwait are tested using cased-hole Drill Stem Testing (DST) system. 15K CT is employed during DST for displacement of kill fluids to achieve under balance prior to perforation, placement of acid for stimulation and for well killing operations. CT operational challenges encountered during testing deep exploratory wells are high pressure reservoir(>10,000 psi), limit on CT injection pressure>10,000 psi, pumping acid of 28% HCL, sour well fluid, salt plugging, etc. Well intervention under such challenging conditions requires proper planning, right equipment, techniques and procedures to ensure safe operation. Existing challenging conditions were well managed and objectives were met. A new problem of formation solids production after acidization of Kerogen rich carbonate/shale formation created a new challenge for CT operations which is unlike the common problem of sand production from the unconsolidated sand stone formation. In some wells, DST string got plugged with solids after acid stimulation and obstruction/stuck-up was encountered while operating CT. Another unexpected problem is the high H2S concentration of 35% in the recently discovered field. The unexpected challenges created unwarranted situation. It is a challenging task for operators to execute the safe and successful CT operations under these uncommon and unexpected conditions. Initially, even some of the service companies expressed their inability to operate CT under these extreme conditions. The unexpected problems are managed well within the available resources and the well test operations were executed safely and successfully. The new solids production operational experience has helped the operator to avoid the reoccurrence of CT stuck up thereby decrease the operational risk and increase the success rate. It has been proved practically in the field that CT can safely be utilized in high sour wells up to 35% H2S and increased the operator confidence. The experience gained, new challenges encountered, safe practices followed and way forward for execution of successful coiled tubing intervention in hostile environment will be discussed in this paper.
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Spatial Modeling of Jurassic Arab Formation Hierarchical Carbonate Depositional Environment Tracts as a Guide to Reservoir Connectivity Anisotropies: An Example from the Dukhan Field, State of Qatar
Authors R. Stanley, H. Al-Ansi, L.J. Weber and J. SnowThe Arab C reservoir interval of Qatar Petroleum’s Dukhan Field is a prolific oil producer. After sixty years of development activity and with hundreds of logged and cored wells, there is an extensive database of rock, geophysical and production surveillance information available for interrogation. The reservoir hosts an accumulation of carbonate lithologies and textures representing a depositional organization of subtidal, intertidal and sabkha environments. A Transgressive System Tract defines the Lower Arab C, migrating upwards from a complex of beach grainstones to a maximum flooding surface featuring muddy carbonates with sporadic encrustations and associated Thrombolite growths. High frequency parasequences within the overlying Highstand System Tract (HST) of the Upper Arab C form a sedimentological pattern from intertidal to sabkha facies, with increasing prevalence of thin isolated high productivity grainstones. From a practical engineering perspective, the upper parts of the HST collocate with development uncertainties associated with erratic patterns of producer support from offset water injectors. Core descriptions characterize these intervals as low permeability mud dominated tidal flats hosting sporadic conductive grainstone tidal channels, leeward of beach barrier islands. Qatar Petroleum has adopted coastal hydrodynamic principles to predict grainstone anisotropic variations. The model for the shelf area has been compartmentalized into depositional tracts based on core descriptions, supplemented by predicted facies at non-cored vertical and horizontal wells using inter-dependent 3D-spatial and 1D log-based fuzzy probability. Vector representations of interpreted tidal flux directions have been used to assign analogy-realistic geometries for beach and tidal channel deposits within an environment of deposition framework. The output distributions reflect a close coupling of control data at wells within the context of sedimentary depositional dynamics, linked to production surveillance. An objective for high resolution 3D static modeling of rock textural and petrophysical anisotropy is the optimization of future infill horizontal wells to maximize IOR sweep efficiency.
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Vertical and Horizontal Pressure Depletion Trends Captured by AVA Geostatistical Inversion Conditioned Reservoir Modeling: An Example From Late Messinian Lacustrine Turbidities Reservoirs, Nile Delta, Egypt
Authors R.D. Vaughan, M. Ali, A. Mustafa, T. Adly, D. Sulistiono and A. PetrovAVO and seismic inversion has been successfully applied during the exploration phase of the Late Messinian Abu Madi Formation in the central Nile Delta of Egypt. Several gas condensate discoveries were made using this technique as a Direct Hydrocarbon Indicator (DHI) and risk mitigation tool. Deterministic inversion was further employed to delineate the overall lateral extent of the field and gross reservoir character during the appraisal phase of one particular field. A comprehensive well data acquisition programme for several wells revealed a complex lateral and vertical reservoir stacking patterns with highly heterogeneous reservoir parameters. The reservoir sequence is attributed to lacustrine turbidities deposited in semi-isolated Late Messinian Basins. Informally, the Abu Madi Formation can be subdivided in to upper and lower members. Intraformational shale barriers and baffles are commonplace. The stacked reservoir sands cannot be visualised and differentiated by the existing deterministic inversion products but each sand package displays complex vertical and lateral pressure trends. This paper describes an AVA Geostatistical Inversion process integrated with rock physics modelling (using differential effective medium theorem) of the wells to generate high resolution multiple rock property models with the aim of capturing reservoir heterogeneity and the observed pressure trends. The probabilistic representations of lithology, water saturation, permeability and effective porosity captured the range of uncertainty remaining after appraisal drilling to provide equi-plausible models to further de-risk future development of the field. Flow simulation modelling is used to monitor and predict pressure depletion trends to optimise further infill drilling and effectively manage the reservoir.
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Proactive Casing Leak Detection Methodologies: a Case History
Authors M.N. Al-Khamis, K. Al-Yateem and E. A. KimaThis paper addresses how high resolution electromagnetic induction was used to study, assess and map the overall well casing integrity of offshore wells and to enable predictions of casing leakage based on the extent or severity of the casing corrosion log. The objective of the paper is to show how proactive detection and prevention of leaks before they occur have guaranteed continuous operation excellence, safety and environmental compliance. These studies were carried out to understand the nature of the corrosion observed. In addition, several other technologies were deployed to effectively detect leaks and further sketch out their location. The lessons learnt and experience acquired during the monitoring and evaluation of casing integrity will be shared. The new technology was used as a tool to establish a casing integrity baseline for an entire field and articulated the new strategic corrosion master surveillance plan. Using the new technology has resulted in a significant reduction in the frequency of routine conventional temperature surveys and therefore optimized resource utilization to foresee other essential jobs.
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Enhanced Reservoir Characterization with Horizontal Well Logs in Dukhan Field, Qatar
Authors A. Al-Naama, A. Al-Sahlawi, R. Stanley, H. Albotrous, B. Ekamba and P. GuoOver the last decade, horizontal drilling has played a significant role in the development of the Dukhan field in Qatar. Optimal placement of high-angle and horizontal wells has ensured economic hydrocarbon production in the Arab oil reservoirs. In the Arab C reservoir interval, stratigraphic layers are generally thin and exhibit a high degree of lateral variation in rock properties and low to medium permeability. Horizontal producers with long lateral sections have increased ultimate recovery by providing greater penetration of oil columns above oil water contacts and by tapping attic oil and isolated reservoir compartments. Sweep efficiency has also been improved through horizontal well waterflood programs. Advances in rotary steerable drilling and logging-while-drilling (LWD) technologies for horizontal wells provide new types of data that can be used for improved reservoir characterization and geologic modeling. LWD sensors are used at Dukhan to acquire real time petrophysical measurements and LWD image logs are now routinely acquired along with conventional triple combo logs (density/neutron/resistivity). A specialized workflow was developed to utilize the LWD image data in log interpretation. This workflow consists of interpretation modules that can be used to define formation bed boundaries and quantify formation property variations along horizontal wellbores. These definitions of 3D bedding structure data and formation properties are then used to condition the geologic model structure and update cell properties. Image logs and petrophysical interpretation results from several horizontal wells will be presented. Comparisons with offset vertical wells are made to illustrate the added value of using horizontal well data in reservoir characterization. Significant uplift in geological modeling is also achieved by incorporating lateral property variation identified through horizontal well petrophysical evaluations.
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Reservoir Simulation Design Strategy for Next-Generation Multi-level Assisted History Matching
Authors S. Mirzadeh, R. Chambers, G.A. Carvajal, A.P. Singh, M. Maučec, S. Knabe, A.K. Al-Jasmi and I.H. El DinThis paper introduces the bases for the design of next-generation automated workflows to implement advanced assisted history-matching (AHM) techniques. The paper presents procedures for geostatistical modeling, high-end dynamic flow simulation modeling, and the use of streamline tracing and visualization to generate a basic (fundamental) model for AHM. The accuracy of the base model is essential because this model is the starting point of the AHM process; therefore, the quality of the AHM process is dependent on the base model. The geomodel benefits from a combination of multiple lithotype proportion mapping (LPM) and plurigaussian simulation (PGS), which successfully represents complex, carbonate depositional settings with eight lithofacies and high-permeability channels. By honoring geostatistical variograms and core-log constraints, a reservoir model is generated with 1.4 million cells. The LPM indicated that 108 layers are sufficient to describe the vertical resolution of lithofacies in the reservoir. A three-dimensional (3D), three-phase, black-oil single-porosity numerical simulation model was developed. The dynamic model has three-phase relative permeability normalization that computes the effects of parameterizing rock type and permeability distribution in the static model. The model is complex, as it has 16 equilibrium regions and two pressure volume temperature (PVT) regions. The simulation model includes 49 wells in 5 waterflood patterns to match 50 years of production, 12 years of injection, and 8 years of forecasting. The model was optimized for minimum simulation time. The base case was used for a) closed-loop, multilevel probabilistic history matching with parameterization of geostatistical and reservoir-dynamic properties and b) dynamic model ranking (DMR) and uncertainty quantification based on predicted oil recovery factor (ORF). This workflow was implemented at the North Kuwait Integrated Digital Field (KwIDF) collaboration center. It generates faster and more accurate history matching updates, produces a high-resolution reservoir model with no upscaling, and calculates waterflood indicators, including voidage replacement, water injector efficiency, producer well allocations, sweep efficiencies, and recovery factors.
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Results from the Introduction of a New 3-d Radial Probe for Wireline Formation Testing in Western Siberia
Authors M. Charupa, P. Weinheber, A. Tsiklakov, A. Latypov, V.H. Goitia, J.R. Caraballo and A. PashinskyThe exploration and appraisal focus in Western Siberia has shifted to more complex and challenging reservoirs. As a result, tools and techniques that may have worked in more benign environments need to be adapted to the more challenging realities. A case in point is the wireline formation tester. The many sizes and shapes that are available have delivered valuable information with respect to rock and fluid characteristics using two basic configurations: either a single probe device or an inflatable straddle packer device. Aside from other nuances, the choice of configuration is essentially a tradeoff between the easy-to-deploy small-area single probe and the difficult-to-deploy but very large-area straddle packer. Into this mix is introduced a new type of probe. This 3-d radial probe attempts to combine the larger flow area of the inflatable dual packer with the easy deployment of a single probe tool. Examples from Western Siberia where all three tools were used are presented to allow us to compare and contrast the performance of each.
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Operational Excellence in Qatar’s First Successful Rigless Heavy Duty Wireline Fishing in a Qatargas Offshore Unmanned Platform
By P.K. DasQatargas North Field wells are typically 7 inch monobore medium to high deviation wells and are designed to handle high pressure sour gas containing of H2S and CO2. An extensive rigless well intervention program is carried out with 0.23 inch electric line and with 0.125 inch slickline for data acquisition, and for other downhole wireline jobs. During a rigless PLT operation with 0.23 inch e-line, an accidental closure of the TRSCSSV resulted in cutting of the e-line. This necessitated a rigless heavy duty wireline intervention resulting in a successful, safe and a cost effective fishing operation in recovering 11,414 ft of 0.23 inch braided e-line. This paper describes the approach and the technique applied in the fishing operation considering the limitations of a rigless operation. It also outlines the extensive workshop trials carried out during the preparatory phase for developing an acceptable double block and bleed barrier arrangement on the PCE for a safe well intervention. It also describes the planning considerations, the procedures developed, the high level Risk Assessment carried out, and the elaborate Load Assessment Study for working with a 90 ft mast and 0.23 inch braided line on a remote un-manned offshore platform.
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A High Field Solid-State Nuclear Magnetic Resonance Experimental Study for Clay and Shale Swelling
Authors M.S. Alzahrani, A.N. Tutuncu and Y. YangReservoir characterization provides one of the key factors of understanding complex shale formations. In this study, an attempt has been made to investigate the NMR response for pure clays in order to eventually use NMR response in developing permeability and porosity correlations for shale formations. The methodology in the study involves using the application of high field solid-state NMR (400 MHz) and incorporating the chemistry of fluids knowledge in saturated clay systems. The high NMR application has the capability to investigate the interlayer and inter-particle spaces in pure clays and detect the change in the structure of clays in different systems through the analysis of the silicon spectra. The expansion mechanisms of clays have been studied extensively and several theories have been developed over the years. The results of this study have been tied to these mechanisms in different clay/fluid systems to comprehend how the associated interlayer or inter-particle porosity affect the total volume change in the formation. The results obtained in our research suggest that the water is adsorbed on the external and internal layers of the clay at the same time, yet at different rates. Under the interaction with highly saline solution, there is a noticably slower diffusion into interlayer space compared to the low salinity or de-ionized water confirmed by the behavior of surface to volume ratios at different porosities. This might be explained as a result of the strong double layer effect (on external surfaces) associated with the high ion concentration. Moreover, the silicon spectra for the saturated montmorillonite showed a minor production of OH- group when exposed to the 8% KCl solution. Yet, no spectra could be detected with the 17.9% KCl suggesting a change in the structure of the clay and hence the adsorption properties of the clays surfaces.
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Field Study: Impact of Risk Mitigation Systems and Solutions on the Fluid Sampling Success Rate and E&P Project Economics of a Large North Sea Field Development Project
Authors H. Castillo, G. Scott and P. WillsThis paper documents the outcome of an eight-year field study that confirmed how the consistent use of innovative conveyance methods and technologies significantly improved the success rate of fluid sampling programs while reducing the overall cost of the E&P projects in long-reach challenging wells part of the largest development project undertaken in the last 25 years in the UK, North Sea sector. The formation properties encountered by these wells along their trajectories, including long deviated sections, posed massive challenges to the acquisition of critical formation evaluation (FE) data, core samples and representative formation fluid-samples required in these wells. In the early stages of this field development, the most significant risks encountered were differential sticking of the wireline-conveyed sampling tools and differential sticking of the wireline in very permeable reservoir rocks. The direct consequence of a stuck sampling tool is the need to fish the sampling tool first and then recover the required fluid samples using pipe-assisted wireline conveyance methods, a sequence that typically takes five additional days. The additional cost to the Project Partners is $4.0 million, based on five days rig spread costs plus the deferred production revenue losses resulting from the five-day production delay of all development wells not yet drilled/completed from the same installation. During the first eight fluid sampling operations in the development phase of this field the fishing rate was as high as 25%. The development and adoption of modern methods and technologies to manage the conveyance risks identified when performing coaxial packer sampling in 2012 resulted in no wireline fishing jobs (0% fishing rate) and no pipe conveyed logging (PCL) operations required (0% PCL rate) on these UK North Sea projects.
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Deciphering the Impact of Subsurface Geology on Reservoir Quality Indicators: Petrophysical Evaluation from Niger Delta
Authors O. Ossai, C. Cavalleri, C. Shrivastava and M. ClaveriePetrophysical properties of subsurface are controlled by the geological evolution of the formation; consisting of structural framework, depositional history and diagenetic changes. Similar well log response can be observed on conventional logs in different settings, often misguiding the petrophysical evaluation compared to the reality, realized due to production discrepancies and challenges in history matching. The Niger Delta marginal marine clastics reservoirs have traditionally been treated as well-characterized for formation evaluation over the years; however, reservoir distribution and quality could be quite variable due to the heterogeneities that went unnoticed while taking production from massive sands. Moving away from the best developed sands, different units were analyzed in the study area with advanced wireline measurements of tri-axial induction resistivity, nuclear magnetic resonance, and dielectric dispersion in the backdrop of geological understanding developed with the borehole images in nearby wells. An attempt has been made to understand the reservoir rock quality and producibility in response to the geological evolution of the subsurface. Thinly bedded reservoirs are discovered and added to the reserves estimate, hitherto overlooked in the study area. Different sand units are studied, trying to understand the geological factors that could impact their producibility behavior. Multiple innovative reservoir quality indicators are listed and further analyzed honoring the geology from different combinations of advanced logging measurements. These include: invasion profile, high resolution volumetric analysis using sand and shale definition from image logs, irreducible water analysis and movable fractions from dielectric dispersion measurement, and magnetic resonance T1, T2 and diffusion constant measurements. Different sand units studied with respect to the developed indicators capture the heterogeneity and resolve for more precise reservoir summation. The well-test results in the study area validate this innovative approach of integrating the geological information with high resolution advanced well-log measurements for developing reservoir quality indicators.
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Fiber Optic Sensing for Improved Wellbore Production Surveillance
Since our previous publication1 significant progress has been made to further mature the application of Fiber-Optic (FO) based Distributed Acoustic Sensing (DAS) for production and injection profiling. A considerable number of new field surveys were conducted to further improve the evaluation algorithms or workflows which convert the DAS noise recordings into flowrates from individual zones. For gas producing wells, a new graphical user-interface has been developed that allows the user to visualize and QC the data in real time. Additional flow and visualization software have been developed for single phase gas producers to enable the user to select and evaluate the data in a user-friendly manner using the most up-to-date evaluation algorithms. There are still improvements to be made in enabling Distributed Sensing infrastructure, such as handling and evaluation of very large data volumes, seamless FO data transfer, the robustness & cost of the FO system installation, and the overall integration of FO surveillance into traditional workflows. It will take some time before all these issues are addressed but we believe that FO based applications will play a key role in future well and reservoir surveillance. In this paper we present two recent examples of single-phase flow profiling using DAS. The first example is from a single-phase gas producer in one of the Unconventional plays in North America and the second example is from a long horizontal, smart polymer injector operated by Petroleum Development Oman (PDO).
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Detecting Leaks in Abandoned Gas Wells with Fibre-Optic Distributed Acoustic Sensing
Authors K. Boone, A. Ridge, R. Crickmore and D. OnenBefore any well is completely abandoned, some jurisdictions have governmental regulations which must be met and carried out by all companies. The main objective of these regulations is to prevent the production of oil and/or gas in the well by isolating and covering all porous zones. Monitoring with fibre-optic distributed acoustic sensing (DAS) systems allows for leak detection within the well bore and mapping migration through the cement with full-wellbore coverage. DAS provides a cost-effective method to accurately determine the depth of a leak or multiple leaks and profile gas movement due to casing failure, failure in wellhead seals, etc. In vertical wells or wells with low deviation, the optical fibre can be easily deployed by attaching a weight bar to the end of a steel tube containing fibre and running it to depth as a temporary installation or left in place as a permanent monitoring capability. Alternatively, a fibre that is already permanently installed behind the casing and cemented in place can also be used. Acoustic events from the gas movement produce a very small strain in the fibre. The strain can be measured at surface and depth-matched using the speed of light in the fibre. After characterizing the flow in the well under open and shut-in conditions, a decision can be made on how to address the leak. This paper will describe DAS technology and how it is deployed as well as show the analysis and results from a casing leak detection trial.
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Upper Oligocene-Lower Miocene Carbonate and Evaporite Depositional Systems of the Northern Arabian Plate
Authors G.J. Grabowski, P.C. Tai, C. Liu and A.O. WilsonThe youngest major reservoirs and seals of the northern Arabian Plate occur in the Chattian, Aquitanian, and Burdigalian. They unconformably overlie major reservoirs of the Oligocene Kirkuk Group, shelfal carbonates formed on the northeast margin of the Mesopotamian Basin. Deep-marine carbonates of the upper-Chattian Ch3 and lower-Aquitanian Aq1 sequences (Serikagni Formation) were deposited within the basin. A thin anhydrite occurs at the base. These pass upwards into shelfal carbonates (Euphrates and Middle Asmari formations), which lie unconformably above older shelfal carbonates around the basin. The basin is completely filled by evaporites and carbonates of the upper-Aquitanian Aq2 sequence and lowstand of the basal-Burdigalian Bur1 sequence (Dhiban Formation and Kalhur Anhydrite). The top of the shelfal carbonates is a subaerial unconformity. Shelfal carbonates (Jeribe and Upper Asmari formations) were deposited in the transgressive to highstand systems tracts of the Bur1 and Bur2 sequences. Subaerial-exposure surfaces are recognized at the top of each of these sequences. Cyclical marginal-marine to nonmarine evaporites, carbonates and siliciclastics (Transition Beds of the Fat’ha Formation, and lower Gachsaran Formation) lap onto the underlying sequences. In parts of northern Iraq the Basal Fars Conglomerate occurs at the base of the Fat’ha Formation, composed of pebbles of the underlying Oligocene-Miocene carbonates and various lithoclasts of Jurassic-Paleogene age transported from the hinterland to the northeast. Deposition of the evaporite-bearing Fat’ha Formation ended in the late Burdigalian to early Langhian. Oolitic-skeletal grainstones and skeletal-peloidal packstones and wackestones of the Euphrates and Jeribe formations are partly to completely dolomitized and have 8-20% interparticle, intercrystalline and moldic porosity and 1-10 mD permeability. Basinal wackestones and mudstones of the Dhiban and Serikagni formations are dolomitic and have 10-17% porosity with <1 mD permeability. Thin limestones of the Transition Beds have 4-15% porosity with <1 mD permeability. Evaporites of the Fat’ha and Dhiban formations are the primary seals for these reservoirs.
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Transforming Seismic Reflection Data Into Quantitative Rock Properties by Seismic Inversion
By S. RajputThe transformation of seismic reflection data into quantitative rock properties can be very valuable in all phases of oil and gas exploration and production. In this study, public domain data from Australian offshore have been used to explain the logical workflow, which consists of systematic steps from seismic petrophysics to rock physics modeling and seismic inversion for quantitative rock property estimation. The application of seismic inversion technology offers many rewards, such as: better reservoir definition and management; better resource estimation; and reductions in uncertainty. The main benefit is that it improves direct and intangible interpretation of seismic data to provide meaningful geological boundaries in the subsurface. In order to provide the reliable estimate of rock properties for reservoir modeling the workflow is tested rigorously and divided into three categories which are based on the basic inversion types. The results reveal that relative impedance inversion should be performed first, which then followed by revision of seismic interpretation on impedance data. Full bandwidth rock properties are estimated by deterministic inversion. The results can be improved by several iterations of well to seismic tie, wavelet estimation, and low frequency models. As resolution with accuracy has always been challenging, the stochastic inversion approach is trailered for reservoir characterization and high resolution rock properties have been predicted. This produces a number of possible rock property models, as well as litho facies models and the results can be optionally constrained by the well data. It can be concluded that, to some degree, stochastic inversion is able to overcome the limited seismic bandwidth by integrating the rock physics properties of different lithologies. The examples of seismic inversion are discussed to demonstrate that significant benefits can be obtained by following an optimized workflow that is tailored to deal with the uncertainties that impact the end product.
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Processing and Preliminary Interpretation of the Ultra High-Density Full-Azimuth 3D Seismic Survey, Dukhan Field, Qatar
Authors S. Seeni, K. Setiyono, H. Zaky, J. Snow and L.J. Weberindustry’s knowledge and experience in acquisition and field operation of ultra high-density full-azimuth seismic has increased over the last 3 years, processing of such data to ensure optimal imaging and reliable reservoir property predictions (e.g., porosity) has lagged. QP believes that lessons learned through this round of processing can provide insight for prediction of rock properties in the major Dukhan reservoirs.
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The Systematic Closing of the Performance Gaps in Hydraulic Fracturing
Authors M. Bychina, V. Guk, D. Wolcott and M.J. EconomidesHydraulic fracturing is the overwhelming completion method in the international petroleum industry. It is estimated, that today it has become a $20 billion industry. It is also one of the most challenging enterprises, incorporating scientific information from geology, reservoir and production engineering, rock mechanics, complex fluid rheology and field economics. More than a decade ago we introduced the concept of Unified Fracture Design (UFD) as a means towards physical optimization. Since then UFD has been adopted by a great number of practitioners and hundreds of papers have been published. Not all approaches have been successful, nor have they been done appropriately. In this work we relook at the whole issue in a systematic way. We have identified and describe here a 9-step sequence to mitigate the gaps and help in the optimized field application of modern hydraulic fracturing.
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Tight Reservoir Stimulation for Improved Water Injection - A Novel Technique
Authors M.Y. Alklih, B. Ghosh and E.W. Al-ShalabiAmong the emerging technologies in the petroleum industry is the application of electro-kinetic phenomena to enhance oil recovery from tight heavy sandstone reservoir, which has been reported to yield technical and commercial success in some of the North American oil fields. The basic theory behind the stimulation effect is predicted to be the colloidal movement of pore lining clays that results in widening of pore throats and/or opening new flow tunnels. Nevertheless, few works have been performed on its applicability to water injection wells. This paper investigates the effect of electrokinetics on improving water injectivity in tight sandstone reservoirs. Two sets of experiments were conducted. In the first set, the DC potential is varied and optimized during the water injection. In the second set, the DC potential is kept constant and the injection rate is varied to determine the hydrodynamic effect on clay movement. The core plugs and liberated clays were characterized through size exclusion micro-filtration and ICP-MS analysis. The Joule heating phenomena associated with electrokinetics is also studied during the entire injection period. Results showed that several folds (up to 152%) apparent increase of core permeability could be achieved. Some of the experiments were more efficient in terms of dislodgement of clays and enhanced stimulation which is supported by produced brines analysis with higher concentration of clay elements. The results also showed larger quantity of clay elements in the produced brines in the initial periods of water injection, prior to the stabilization of differential pressure and electrical current, implying that the stimulation effect stops when the voltage gradient and flow rate values are no more able to remove additional clays. Additionally, fluid flow temperature measurements showed an increasing trend with the injection time and direct proportionality with applied voltages.
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Dipole Shear Imaging behind casing: Extending the Borehole Acoustic Imaging envelope to Brown-fields
Authors A. Srivastava, H. Yamamoto, S. Ahmed, J. Roberts, F. Cantin, O.-D. Moreau and N. BounouaThe potential for imaging bed boundaries and fractures using the borehole acoustic reflection survey (BARS) technique is well documented. Traditionally, this type of imaging has been conducted with a monopole source and imaging the reflected P and the mode-converted transmission waves (Pto S and S to P). Recently the BARS methodology has been applied to shear data from a dipole source. Much of the published work is in an open-hole environment. In our case study a BARS image was acquired in a layered carbonate reservoir in a horizontal well behind casing. The objective was to acquire a base image prior to a planned hydraulic fracturing job for comparison with the post-fracturing image. Both, monopole and dipole data were used to do the imaging. Data acquired shows that the BARS technique overcame uncertainties associated with; arrival of the casing modes, cement conditions, attenuation of the reflected signal at the casing/cement/formation interfaces and provided reliable results behind casing up to a distance of 100 ft away from the well.
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Identifying Opportunities in a Complex Mature Oil Reservoir; a Company’s Experience
Authors E.A. Omara, A.F. El hawary, M. Nosseir, A. Samieh and M. BaydoonThis paper presents a case history of defining the field development plan for a complex; heavily faulted layered; undersaturated oil reservoir, with significant degrees of structural and production uncertainties. In such case, good reservoir management practices and reservoir monitoring are the main keys to understanding the reservoir behavior. The reservoir has numerous challenges, which complicate reservoir management; like complex geology, pressure support for different layers, water injection optimization, scale depositions, and commingled production which introduces uncertainties regarding the production and injection contribution. This leads to difficulties to identify bypassed oil in the reservoir. Therefore frequent production logging, monitoring the producing water salinity, and key data from wells and RFT/MDT of the new infill wells were used for managing such uncertainties’. This served as primary keys to identify different vertical and lateral flow barriers, and was used as a basis for water injection optimization in such challenging conditions. The reservoirs were studied by means of analytical methods and integration approach of wells’ and reservoir surveillance data for understanding the structural configuration, investigate various production problems, optimize water injection strategy, and identify bypassed oil and poorly swept areas. The methods defined an extensive portfolio of infill drilling and other cost saving rigless activities to restore production potential of the field. This approach added about 22 MMSTB of oil reserves which represent 8 % increase in the ultimate oil recovery, and flattened the oil production for more than 5 years. New infill wells were confidently identified to achieve all of the following objectives a) access bypassed reserves b) access attic oil reserves c) adding another drainage point to the existing producers. The presented reservoir management practices has proven its ability to timely support the operational decisions, pinpoint infill wells, and prolong the life of a mature asset. It is not moving away from detailed dynamic model, but these practices are required in similar uncertainties conditions to develop right sense of understanding of reservoir behavior, and provide invaluable input data which adds credibility to the dynamic model.
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Challenges of Drilling HPHT High H2S Content Well Focusing Effective Well Control Measures with Consideration to SimOps
Authors F. Al-Qattan and M.A. AlamDrilling of HP / HT well have been always challenging due to contrast in formation pressure. These challenges become more complex particularly when drilling a formation of high H2S content. Kuwait has a structure of very high H2S content (20%-35%), located in the North Field which are drilled and developed under extreme precautionary measures considering the highest potential risks on simultaneous operations and infrastructures in the area. Formations of this structure are deep (13000 – 17000 ft) and naturally fractured reservoir with very low porosity and permeability. Since the reservoir is rated as HPHT and sour, it was a highly challenging experience to manage drilling operations and preventing well control situation. Unfavorable conditions such as high pressure, high temperature and high H2S content require special attention on appropriate mud weight balancing formation pore pressure, mud loss scenario and availability of ready to use adequate quantity of LCM pill to prevent well control situation through integrity of surface equipment such as well head, kill line, choke manifold, high pressure cementing unit, BOP and H2S Management Plan. During drilling of the targeted formations at one of the wells, a severe mud loss situation was encountered followed by H2S alarm and subsequent Well Control Scenario, which brought forward weakness in confirming wellhead integrity due to lack of secured system for periodical BOP function test. The situation was brought under control through well-coordinated effort without causing any injury to the crew at site. The several simultaneous operations (SimOps) like drilling, well servicing, hydrocarbon processing, gas injections etc at nearby facilities such as wells, flowlines, pipelines, manifolds, ESP, rigs, processing facilities makes the matters further challenging, which needs to be cautiously managed without aggravating the situation. Aim of this paper is to describe the actual challenges encountered and lessons learned from HP / HT extremely sour well under well control scenario with complex SimOps environment. This paper also aim to present techniques and approach adopted to address the operational risk and HSE issues for BOP functional test, wellhead integrity, mud management priority supported with comprehensive H2S management program.
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Automation of Well Modeling and Data Validation for Reservoir Simulation
Authors M.A. Al-Ismael, H.A. Nooruddin, Y.A Al-Quhaidan, H.A Al-Khawaja and M. ShedidHydrocarbon wells are the most critical and challenging asset in any oil and gas field development and operation plan. The quality of the history matched reservoir simulation model and reliability of future field performance forecasts depend heavily on the accuracy of the well model. In typical reservoir simulation studies, a tremendous amount of time is devoted to gather and validate data required to construct the simulation model, particularly well related data, including well trajectories, completions, production and injection rates, well logs and downhole flow control devices. This issue can become more challenging when thousands of wells are involved with multiple configurations and complex completions. Therefore, it is critical to ensure the quality and accuracy of well data to have consistent, comprehensive and reliable reservoir models that can be used to forecast reservoir performance. In this paper, an advanced system for extracting, validating and pre-processing complex well information from the corporate database to perform well modeling and simulation is presented. The paper demonstrates how this system ensures the validity and accuracy of well models by applying advanced quality control measures with strong capabilities for detecting data inconsistencies. The paper starts with a description of the system and how the pre-processed wells contribute in building an integrated environment to serve complex well modeling. The paper demonstrates that the quality control process leads to an automated, efficient and easy well data processing procedure with a significant degree of reliability. In addition, real cases and lessons learned from this experience are discussed. The system implements new design and algorithms while dealing with a massive amount of data gathered from giant onshore and offshore oil and gas fields. This paper shows how Saudi Aramco applies creative solutions for the best utilization of the Upstream corporate data to support decision making, increase productivity and save costs.
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Adaptive Sobel Based Edge Detection for Enhaced Fault Segmentation
By A.A. AqrawiIn this work, we suggest an improved method of traversing post-stack seismic data with an adaptive operator size for detecting edges. Attributes, in the coherence family, used for edge detection usually have a static operator size (Marfurt and Chopra, Seismic attributes for prospect identification and reservoir characterization, 2007). This can prove to be limiting in that one would under or over sample in regions of higher or lower frequencies respectively. By looking at the nature of seismic data, which commonly changes from short wavelength to longer wavelength signals in depth/time, an adaptive approach is more suitable for detection of features. By adjusting the operator size in relation to the depth/time, we are better following the frequencies of the data as we filter them. To increase the accuracy and resolution of our filtering we have chosen to interpolate between adjacent seismic traces. However, seismic data is not that simple in structure such that one can only vary in depth/time. Geological features such as dipping, salt and gas result in chaotic and varying frequencies regardless of when they occur. This is why we have introduced a textural analysis to account for this change and adapt our filtering to it. We have chosen to use chaos (Iske and Randen, 2005) as our seismic texture change indicator, as we are looking for changes to higher frequencies that usually results in chaotic textures. The attribute we have chosen to implement is a 3D Sobel based edge detector, namely amplitude contrast (Aqrawi & Boe, 2011). In essence, the textural analysis in this case will decide the outcome of two things. One, the choice of preconditioning prior to filtering, and the second is the normalization method used. While, when implementing the operator size of our edge filter, relative depth/time is used to adjust it adaptively. As such, the algorithm operator size is time variant and accounts for seismic texture by varying the selected algorithm to filter with and the appropriate operator size to do so. To test our algorithm, a heavily faulted seismic dataset from the Norwegian North Sea has been used to test the methodology of the adaptive calculations. Our results indicate that the adaptive edge method ensures a higher level of detail, and highlights the smaller amplitude discontinuities better than a static operator size approach. It also proves to increase continuity and reduces the detection of noise, which overall gives a more accurate edge detection of the seismic data.
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A Receiver Array Evaluation Method Designed For Surface Based Microseismic Monitoring
Authors N. Aoki, E. Asakawa and S. AbeSurface based microseismic monitoring during hydraulic fracture stimulations is an emerging technology in the last decade. The method observes acoustic emission (AE) or microseismic events using a surface receiver array and estimates source locations and origin times of the events by analyzing a time series of migration images from observation data. However, the accuracy and monitoring cost of the technology highly depends on the array-geometry. The migration images can be blurred if a too coarse array is used. Monitoring cost can be unnecessarily high if a too dense array is used. Some sort of adequate array evaluation methods are required for designing a cost effective survey plan. We introduce an array evaluation method based on the point-spread function (PSF). The PSF describes the response of an imaging system to a point source. Our proposed method evaluates an array in the following way: First, a point source of which excitation time and source location are known is defined. Second, synthetic seismograms using the array are computed. Third, the synthetic traces are migrated and a time series of source images are obtained. Finally, the images are examined so that the abilities of the array are understood. We demonstrate the method by diplaying attributes calculated from the dataset which represent the precision and accuracy of the source location determination.
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Using Stochastic Seismic Inversion as Input for 3D Geomechanical Models
Authors T. Trudeng, X. Garcia-Teijeiro, A. Rodriguez-Herrera and J. KhazanehdariThe dual issues of band-limited vertical resolution and nonuniqueness of deterministic inversion results has led to the development of methodologies known as geostatistical, or stochastic, inversion. In these approaches, seismic data are typically inverted directly into a high-resolution geological model. Compared to deterministic inversion, stochastic methods deliver multiple realizations that are consistent with the available well and seismic data. The seismic inversion process is inherently nonunique, meaning that there is an unbounded number of elastic property models that fit the seismic data equally well above some threshold misfit. We explore the notion of the equally large number of possible stress states that could be interpreted from same seismic observations. We make use of stochastic inversion results to incorporate the impact of subseismic uncertainty in seismic-driven geomechanical models. By taking multiple realizations from a prestack stochastic inversion—acoustic impedance, Vp/Vs, and density—we generate and feed a series of distributions of elastic constants into a finite element stress simulator. The multiple stress solutions allow us to account for uncertainties in the inversion results that can be ultimately captured in a suite of numerical models to predict a set of possible geomechanical states of a field. Therefore, beyond a unique geomechanical forecast for a field, we can now solve for the range of variability in geomechanically safe operational parameters within the field’s development plan.
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Basin-Scale Simulators for De-Risking of Unconventional Play-Types: A Practical Approach to Enable in-time Decision Support
Authors M. Keym, O. Meuric, P. Kuhn, C. Buerger, V. Dieckmann, O. Podlaha and W. SeniorUnconventional resources have emerged as an important part of the world's energy supply. Engineering technological advances such as drilling horizontal clusters and completion solutions like hydraulic fracturing have contributed to the exponential growth of unconventional opportunities and their exploitation. Still a lot of headroom is left for a deep and improved understanding of the subsurface geologic controls on hydrocarbons’ fluid movement and trapping characteristics. These characteristics are becoming paramount to de-risk the presence and extent of producible hydrocarbons in current and upcoming resource play opportunities.
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Blended Source/Nodal Ocean Bottom Seismic Acquisition
More LessOcean bottom seismic (OBS) data have been used for appraisal and development applications for a number of years in the North Sea, West Africa, Gulf of Mexico, and more recently offshore Brazil and SE Asia but the scale of the surveys, by dint of their focus on field specific imaging, has been limited compared to towed streamer surveys in both size and duration. One of the challenges set by the oil companies has been to reduce the unit costs of OBS data – “If only the square kilometer rates were lower we would shoot more data” is a common mantra. The difficulty in doing this has been the inherent technical downtime experienced by all the contractors operating ocean bottom systems – the terminations, connectors, power distribution and data telemetry components within a traditional ocean bottom cable (OBC) system are inherently prone to failure due to the intrinsic nature of the cable deployment/recovery cycle where the cables are stressed and de-stressed every time they are laid onto/recovered from the seabed. It is akin to recovering the full streamer spread every line change for towed streamer operations. The desire to improve operational performance was the driving force behind the development of the Z700 autonomous nodal system and its extreme reliability has allowed ever larger seafloor spreads to be operated which has multiple benefits.
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Complementary Data-driven Methods for Interbed Demultiple for Land and OBC Geometries
More LessInterbed multiples occur in all types of seismic datasets and are difficult to address. These multiples can appear very similar to primaries due to comparable velocities, and may be difficult to differentiate from primary energy and/or distort the amplitude of primary reflections. Interbed multiple prediction (IMP)-based on the 1D earth assumption and applied to post-migration gathers has been partially successful in removing these complex multiples, but cannot be considered a full solution as it is applied late in the seismic data processing sequence, limiting the derivation of an accurate velocity, which is critical for imaging, time or depth, and for further reservoir characterization. This problem is further compounded in onshore and OBC seismic data. These, in general, have wide acquisition geometries and suffer from poor sampling, especially for shallow reflectors, which adds to the challenges of multiple attenuation. In this paper, two complimentary data-driven multiple attenuation techniques are discussed (Deterministic interbed demultiple (DID) and Extended interbed multiple prediction (XIMP)). These address the various challenges posed by the complexity of acquired data and the generated interbed multiples. We demonstrate complementary approaches to address the challenges of interbed multiple attenuation in land and OBC environment and show a case studies from seismic datasets. As there is little or no discrimination in velocity or dip, multiples cannot be easily attenuated using conventional methods based on periodicity and velocity or dip discrimination. To address the specific challenges of each survey, a careful analysis of the data is required and usually a combination of methods and approaches is the best solution. DID and XIMP are methods that naturally complement each other, allowing compensation for the limitations of land and OBC geometries and addressing the full interval of the multiple generators from top to bottom of the section.
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Maximum Recovery of Gas Compression Waste Energy
Authors N.A. Ansari and S.A. SaluThis paper presents a revised energy efficient compression scheme to maximize recovery of wasted energy from a conventional gas compression scheme, which is highly prone to wastage of substantial amounts of energy at different stages in the process. A typical compression process requires a discharge gas cooler and an anti-surge control system. The common means of cooling the compressor discharge gas is by using either fin-fan air coolers or a cooling water system that eventually dissipates the heat energy of the gas to the environment. Similarly, in a fixed speed driven compression system, significant energy is wasted due to recycling of compressed gas to the suction through the anti-surge control system to satisfy fluctuations in production rates. In the revised scheme, the compressor discharge gas fin-fan cooler/water cooler will be replaced by an evaporator of an advanced Special Rankine Cycle (SRC) to capture thermal energy from hot discharge gas and convert it to power output in a turbine. A refrigerant mixture that will be thermodynamically efficient at the operating temperature ranges and environmentally friendly will be required. Combining the SRC discharge gas cooling with the use of a compressor driver that has full variable speed capability will greatly optimise compression energy recovery. Use of gas turbine drives will provide additional opportunity to recover waste heat from the driver’s flue gas in the SRC. The proposed energy efficient gas compression scheme will also enable lowering the compressors suction temperature to the minimum temperature possible to reduce compression energy requirement. A case study of applying the proposed scheme in a Saudi Aramco gas compression plant is presented with an energy saving analysis. Overall energy recovery of about 45% is achievable. The new scheme will provide significant economic and environmental benefits as a result of the substantial energy recovery.
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Fischer-Tropsch Synthesis in a Microchannel Reactor: The Influence of Co/SiO2 Catalyst Structure on FTS Performance
Authors H.J. Robota, L. Richard, S. LeViness and S. DeshmukhConversion of synthesis gas into clean diesel fuel from natural gas (Gas-to-Liquids - GTL) via a Fischer-Tropsch synthesis (FTS) process can provide an economical way to create value from unconventional, remote and problem gas. However, conventional processes, fixed-bed and slurry phase, are not economically viable for the smaller plants required for processing stranded natural gas fields. On the other hand, a microchannel reactor for FTS offers the opportunity for a small, modular, less expensive and high efficiency facility. Over the past several years Velocys has been engaged in not only the development of microchannel reactor technology for FTS, but also supported cobalt catalysts that provide the necessary level of C5+ productivity for an economically viable process. The influence of support properties, synthesis methodology, cobalt loading and promoters on catalyst performance has been studied. For example, it has been determined that both the support surface chemistry and the Co particle size distribution have a strong effect on the rate of catalyst deactivation for Co loadings >40%. In this presentation the authors will show how the structural properties of a Co/SiO2 catalyst are influenced by both the surface chemistry of the support and the method of synthesis. Catalyst characterization data will be used to explain observed FTS performance in a microchannel reactor.
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Modeling Bitumen Presence and Its Impact on Reservoir Performance in the Arab D Reservoir, Dukhan Field, Qatar
Authors F. Hasiuk, A. McKinney, F. Meek, B. Dwiyarkoro, H. Jamieson, H. Al-Ansi and J. K. MillerA recent integrated geologic modeling and reservoir simulation history-matching effort in the Arab D Reservoir, Dukhan Field, Qatar, has found that the presence of bitumen and the extent to which it saturates porosity and impairs permeability are the key factors in matching water production history in wells located near the oil-water contact (OWC). By using production data, the ability to predict the location and continuity of permeability-reducing bitumen was greatly increased. In this study, many past attempts at visual and petrophysical identification of Dukhan Arab D bitumen were quantitatively compared, and visual macroscopic core descriptions were found to be the most accurate. By integrating core and petrophysical data with the structural history and the timing of hydrocarbon migration and bitumen generation, a predictive model was constructed to identify the part of the reservoir most likely to contain bitumen, the “bitumen prone interval” (BPI). Within this interval, the presence of bitumen was determined stochastically away from well control using facies modeling techniques. In each bituminous cell, bitumen saturation was calculated through statistical analysis of core plug porosity data from inside and outside the BPI. The resulting reservoir model provided both a conceptual match to the working knowledge of bitumen distribution at Dukhan and a directional match to the overall field production history. However, this approach was unable to match individual well performance or the variability in areal sector behavior with a high degree of accuracy. While direct observation of bitumen is limited to cored wells, producing wells above the BPI provide indirect evidence of bitumen presence for model calibration. Through iteration with the dynamic reservoir simulation model, bitumen distribution, saturation, and permeability were modified systematically within the predicted BPI to better match the behavior of both individual wells and areal sectors of the field.
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A Study of Acoustic Wave Propagation inside Cemented Production Tubings
Authors A.K. Farraj, S.L. Miller and K.A. QaraqeWell operators use advanced downhole telemetry systems to monitor the flow rate, temperature, and pressure inside the well. The wired telemetry tools are currently popular in the industry although these tools have cost, maintenance, and reliability issues. Acoustic waves that propagate by vibrating the pipe’s body inside the well were recently considered as an alternative technology. However, the bottom segment of the production tubing is encased in concrete in many wells; a previous work showed that concrete segments attenuate the acoustic waves to impractical levels, which limits the applications of this mode of propagation. As an alternative to vibrating the tubing body when there is a concrete segment over the pipe, this work investigates the use of the production tubing’s interior as a communication medium for the acoustic waves. A testbed was designed using five segments of 7-inch production tubing to form a pipe string, a speaker to generate the acoustic waves, and a directive microphone to receive the acoustic waves propagating inside the pipe string. To study the effect of cemented pipes on acoustical wave propagation, the third pipe segment was encased in concrete. Input frequencies from 100 Hz to 2000 Hz were investigated; wave measurements were taken along the pipe string, and measurements were analyzed to extract information about the behavior of the acoustic channel. This work shows that acoustic waves are not affected by the presence of the concrete segment. Low-frequency acoustic waves experience very little attenuation as they propagate through the interior of the pipe string, signal dispersion is not an issue for most frequencies, and delay spread measures increase as the acoustic waves propagate down the pipe. This work advises that acoustic-wave technology can be a promising cost-effective and reliable solution for wireless downhole communication systems. Technical contributions include: characterizing the channel response to different input frequencies along the pipe string, investigating the power spectral density and signal-to-noise ratio measures, and studying the time dispersion parameters of the channel.
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Well Structure Integrity Threat Due To Near Surface Corrosion of Outer Casing at Offshore Wells
Authors S.K. Pandey, S.A. Rana and A.J. FakhrooQP Offshore operates in shallow water at Arabian Gulf. The wells are drilled and completed at surface on multi slot wellhead jackets. We encountered well subsidence with some offshore wells. The well subsidence caused stresses to flowlines, gas lift hook up and jacket members. As a result, the flowlines and gas lift hook up were under threat with subsided wells. This meant high risk potential of uncontrolled release of hydrocarbon to atmosphere, with significant potential of asset damage and environmental pollution. The Offshore wellhead jacket structure and conductor casings are protected against corrosion by cathodic protection. These were primarily installed to protect wellhead jacket structure against sea water and its corrosion protection to wells is not known to us. The well subsidence occurred due to structural failure of outer casing caused by the atmospheric corrosion. The corrosion occurred due to outer casing being in contact with sea water and atmospheric air near splash zone. We looked at options of isolating the air and seawater contact from outer casing to prevent further corrosion. It was possible to achieve this by placing bio degradable oil into Conductor. The oil being lighter than water shall stay above the water, thereby isolating air in the oxygen from sea water. We dropped this option as high ambient temperature in summer months shall cause bacterial growth and degrade oil. The degraded oil could result in accelerated corrosion instead of preventing it. The other option considered was to install sealing type cover at the top and replace trapped air inside annular space with nitrogen. This too could not find favor due to lack of assurance in isolating the air inside the Conductor. QP selected to top up the conductor with cement. It shall cut off air between conductor and outer casing. The other major advantage was well structure strengthening by joining the conductor with outer casing to support wells with weakened outer casing. The paper shall illustrate on the findings of corrosion analysis with outer casing recovered during well workover operations for subsided wells.
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Low Salinity Flooding: Experimental Evaluation and Numerical Interpretation
Low Salinity Flooding (LSF) is an emerging technology to improve oil recovery for both sandstone and carbonate reservoirs. Extensive laboratory experiments investigating the effect of LSF are available in the literature. To quantify the low salinity effect, spontaneous imbibition and/or tertiary waterflooding experiments have been reported. In only a few published cases, the experimental data was interpreted using numerical simulation to derive relative permeability curves for both low and high salinity water, to be used in field simulation. A critical review of the literature data shows a wide spread in the LSF response in both pressure and recovery. Moreover, most of the flooding experiments reported in the literature are performed at a low flow rate, of ~1 ft/day, which may lead to a significant capillary end effect and, consequently, to a possible overestimation of the LSF effect. The focus of this paper is on: 1- The experimental procedures used for proper evaluation of the LSF effect; 2- Reporting experimental data performed on sandstone samples in both tertiary and secondary mode waterflood; 3-The numerical interpretation of the laboratory data to obtain relative permeability and capillary pressure curves for both high salinity (HS) and low salinity (LS) water, to be used in reservoir simulation to quantify the benefit of LSF on reservoir scale and 4- Investigating whether the tertiary flooding experiments can be used to derive relative permeability curves for both HS and LS waterflooding. The main conclusions of the study are: 1- While spontaneous imbibition (SI) experiments could provide an indication of a potential low salinity effect, they are not sufficient to quantify the effect in flooding experiments; 2- The LSF effect measured during low rate flooding experiments (i.e., field rate) is not representative for the field scale as it is usually dominated by capillary end effect. Therefore, the low rate (raw) coreflood data will suggest a larger LSF benefit than would actually be the case; 3- The tertiary mode experiments cannot be used to derive the LS relative permeability curves as it only spans a narrow saturation range during LSF and 4- Both tertiary and secondary mode corefloods performed using multi-rates are required to obtain relative permeability curves for HS and LS water.
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Opening the Black Box: A Critical and Comparative Investigation of Solvers and Methods in Conventional and Next-Generation Reservoir Simulators
Authors C. Temizel, B. Hancioglu, S. Purwar, S. Dursun and S. TekThe term “next-generation” has been used related to reservoir simulation within the industry for almost a decade. This paper discusses factors that make next-generation simulators more special and effective than well-known previous methods by outlining the basis as well as the differences between the methods. The conventional reservoir simulator discussed makes use of the fully implicit (FI) and implicit in pressure / explicit in saturation (IMPES) methods. Fully implicit methods are more stable than explicit methods; however, more core memory and computation effort per time step are required when using fully implicit methods. Time truncation errors encountered when large time steps are used and the difficulties with implementation of higher order methods to reduce spatial truncation are some of the drawbacks of fully implicit formulations. Krylov subspace algorithms are the sole option for linear system solvers. The next-generation simulator discussed uses a relaxed volume balance approach, which is better than a mass balance formulation because the volume balance is a local error, and does not accumulate over time. The volume balance is simply the difference between the fluid volume and the pore volume in each grid block in the model, and is the primary convergence criteria in a volume balance model. A review and systematic comparison of solvers and solution methods is provided, such as finite difference methods (FDMs) and finite element methods (FEMs). Finally, the results of runs conducted on the SPE CSP 9 from both “conventional” and next-generation simulators are provided along with a comparison of processing times.
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Ensuring Safety of Residents in an Emergency Planning Zone While Maintaining Sensitive Public Relations with the Affected Residents - Best Practices Shared
More LessEstablishing an Emergency Planning Zone (EPZ) map lays the foundation for a successful Emergency Response Plan. A safety company was tasked with the responsibility of ensuring the safety of residents living in a neighboring community where potentially hazardous drilling activity in a critical sour well with high H2S concentrations and potential high release rates was about to commence. The safety company was responsible for managing and monitoring the EPZ while constantly updating residents about progress on the drilling activity. An EPZ of 5.8 kilometers and an awareness zone of 11.6 kilometers were identified; the area of management contained one town and two hamlets of roughly 2000 inhabitants. To effectively monitor and ensure the safety of residents within the EPZ, the safety company dispatched and managed close to 100 onsite personnel. This large team was responsible for manning roadblocks, monitoring the various zones within the EZP, and maintaining buses on standby to evacuate low mobility groups. Another key element of this project was the successful handling of crucial public relations to defuse and manage potentially very tense situations. The sensitive nature of the issue required careful, consistent and regular communications as residents needed to be constantly updated on the impending drilling operations. To handle the daunting community relations issues effectively, the safety company deployed a number of ‘rovers’ to monitor and communicate with the public through house visits. A call centre was also set up for residents to reach out for more information. The project was so effectively managed that it even superseded the expectations of the regulatory body responsible for overseeing the drilling project. This paper will discuss in-depth details, learnings, insights and the various factors that were responsible for making this Emergency Response Planning project such a complete success.
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First Steps Toward Maturing the Shallow Gas Play - Results of an Integrated Exploration Workflow
Authors J.H. Ten Veen, J.M. Verweij, G. de Bruin and T. DondersRecent exploration activities in two of the largest deltas in the world, the still active Nile delta and the Cenozoic Southern North Sea (SNS) deltas, proved the potential of shallow gas resources. Although, previously seen as a hazard or an exploration tool for deeper hydrocarbons, the shallow gas accumulations may represent a valuable additional hydrocarbon resource, especially if located near existing infrastructures. Nonetheless, shallow gas production is still limited due to a lack of insight in the petroleum system. Knowledge on the geological conditions that enable accumulation of shallow gas is essential since gas at these depths is highly buoyant, and tends to migrate towards the surface. Furthermore, the nature of these accumulations depends on the type of sediment and the anatomy of the delta they reside in. In order to mature the shallow gas play, a multidisciplinary workflow was applied to the SNS delta that involves 1) the reconstruction of the internally complex delta body, 2) a combined deterministic/stochastic approach to make reservoir property predictions, 3) evaluation of the HC origin, and 4) a grain-size based method to predict the seal-integrity of the sealing clay layers. The results include a first evaluation of the potential of shallow HC accumulations in terms of trapping geometry, seal capacity, sourcing and migration. The presented workflow is applicable to areas where limited exploration data is available, but where critical production data is (still) missing. By reviewing the HC systems of the Nile and SNS deltas many similarities emerge that are expressed by 1) the control of sea-level and climate on the distribution of reservoirs, seals and organic material, 2) the presence of stratigraphic traps and 3) the role of deeper salt and faults in the formation of structural traps. For both settings, the origin of the shallow gas may be deep subsurface thermogenic sources or biogenic sources in shallower strata, or a mixture. To date, reserve estimates for the shallow gas play are often hard to make using conventional exploration techniques due to the inability to discriminate high vs. low saturation shallow gas. The potential of pre-stack seismic inversions or other geophysical techniques such as CSEM appear essential in maturing the Shallow Gas play.
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Effective Utilization of Smart Oil Fields Infrastructure towards Optimal Production and Real Time Reservoir Surveillance
Authors M.A. Al-Amri, F. Amizadh, K. Yateem, R. Ahyed and F.T. Al-Khelaiwichokes and inflow control valves (ICV). Lately, the concept of intelligent field has been embraced by more and more operators with expectations for higher recovery from the reservoir. In addition, installation of permanent downhole monitoring systems (PDHMS) in both free flowing and ESP equipped wells provides continuous monitoring of reservoir parameters as an indispensable tool for reservoir surveillance. Their installation eliminates well intervention data acquisition operations and reduces non-productive shut-in time during rig-ups which enables significant improvement of reservoir surveillance in real-time and focused utilization of resources in material or human capital and assets. Saudi Aramco is tackling existing problems through the utilization of technologies from smart multilateral/MRC wells and mega-cell reservoir simulation to the implementation of fully integrated intelligent fields and geo-steering on real-time mode, all offering a wide-range of interdisciplinary domains for development and progression. This paper will discuss the integration of smart sensory and control devices within the company’s fields, deployed towards finding the optimal production strategy whether naturally or artificially lifted, meeting the designated targets and providing the much-needed flexibility in its operations. The latter is of particular importance in fields which are located in remote, offshore, or near populated areas where safety considerations dedicate less human intervention. In addition, effective methodologies of data mining and computational modeling are necessary to attain these goals. Such methodologies are effectively placed to ensure the best utilization of integrated operations, as well as obtain accurate and useful data flow paths. In a nutshell, the implementation of technological advancements results in a positive impact in field performance on a real time fashion, extending the producing life of wells, harmonizing sweep efficiency and ultimately maximizing oil recovery from the fields.
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Subsurface Cuttings Injection: Technical Challenges and Opportunities
The progression of new and remote field development, including arctic and deepwater, inherently increases the volume of cuttings and waste generated from drilling, completion and production operations. The economic and environmental impact of this waste management including transportation, treatment and final disposal is considerable and can be drastically decreased through subsurface cuttings and waste injection. This environmentally friendly disposal solution provides an effective and practical way to minimize associated health, safety and environmental risks by eliminating transportation needs and potential accidents, and therefore reducing the long-term project environmental footprint. Nowadays, cuttings injection is considered a proven technology for the final disposal of drilling waste through subsurface injection into an engineered subsurface strata or formation where the injected waste is safely contained for permanent storage. The logistical constrains of transporting large volumes of produced waste to the final disposal site poses many challenges in large-scale field development, where the most cost-effective solution is often to drill a dedicated injector well, process and inject all the produced waste at the single cuttings injection site. An application of comprehensive fracture-mapping techniques is a major step in ensuring that the target formation will be suitable to accommodate all waste volume injected. Fracture mapping the waste domain complexities represents valuable information, not only in the overall planning of drilling operations, but in the fundamental and invaluable need to provide sound engineering and assurance for the waste subsurface containment. This papers describe the driving factors and opportunities for implementing cuttings injection in one of the largest and complex development projects in the northern part of Caspian Sea where ecologically sound drilling, stringent environmental regulations and “zero discharge” policy commitment are critical for the success of the drilling operations and overall field development.
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Extended Elastic Impedance – A Time-Efficient Workflow from Prestack Seismic Data, Through Rock Physics, to Reservoir Properties
Authors K. Westeng, T.A. Hope and A.E. RasmussenThe use of extended elastic impedance (EEI) as described by Whitcombe et al. (2002) gives promise of a fast and objective way to relate seismic inversion results to different reservoir properties such as, e.g., porosity, fluid content and lithology. This can be a useful tool for exploration, prospect evaluation, and early reservoir characterization. At the same time it is generally less time consuming than other methods such as simultaneous AVO inversion combined with rock physics inversion or lithology/fluid facies classification studies. Two key elements in the EEI workflow are to find the correct chi angles projections used for relating the EEI to different elastic properties and to estimate and select the right wavelet for the inversion of the 0° and 90° EEI. Herein, we will show how rock physics modeling, fluid substitution, and the selection of input data can be crucial to obtain quality results and also in situations where modeling will not be necessary. In addition, we will demonstrate how the EEI inversion workflow can be constructed to be time efficient and to provide quality results. An offshore exploration example will illustrate the possibilities and results with this workflow, where the results were used in prospect evaluation, de-risking, quantitative interpretation, and separation of brine vs. hydrocarbon-saturated sands.
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Origins of Evaporites in a Holocene Mixed Clastic and Carbonate Coastal Sabkha: Preliminary Hydrological and Geochemical Data from Mesaieed Sabkha, Qatar
Authors F. Whitaker, S. Mey Didi-Ooi, J. Jameson and C.J. StrohmengerModern sabkhas are recognized as analogues to ancient evaporitic reservoirs and as Earth analogues to Martian paleoenvironments. Sabkhas are normal marine coastal sediments modified by groundwater precipitation of evaporites and carbonates. Previous work on Holocene sabkhas has focused largely on dolomitisation in carbonate-evaporite systems. Little attention has been given to understanding the origins of evaporites in mixed clastic-carbonate systems and their influence on reservoir quality. Extensive and detailed geomorphological and sedimentological characterization of depositional environments in Qatar provides a framework within which to understand processes controlling the origins of evaporites, their spatial distribution and likely evolution through time. Mesaieed sabkha is a 4-6 km wide coastal plain which consists of an onlap wedge of Holocene sediments some 3-6 m thick reaching a maximum of 15 m, which onlaps onto Eocene bedrock. Within the sabkha, gypsum is the most abundant diagenetic mineral, reaching 20-50% of the sediment volume over several square kilometres, with minor calcite, dolomite, anhydrite and halite. Gypsum cementation is pervasive above and below the water table in the proximal sabkha, in sediments dated c.6,000 years before present (yr BP), whilst in the central part (c. 4,000 yr BP) gypsum is restricted to surface crusts and water table cements, and is largely absent in the distal (coastal) sabkha (≤ 2,000 yr BP). Preliminary analysis of hydrological and geochemical data suggests evaporative pumping of groundwater from the underlying aquifer is an important source of solutes in the upper part of the sabkha, whilst seawater recharges the lower sabkha via the porous and permeable Eocene carbonates. Evaporation close to the water table results in fluids reaching gypsum saturation, and active precipitation of gypsum is evidenced by depletion of calcium and sulphate in the shallow brines. This is most marked in the middle part of the sabkha where salinity is highest. These increased density fluids reflux downwards from the Holocene, to mix within the Eocene aquifer, where reaction with the Eocene carbonates results in relative enrichment of calcium.
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On the Impact of Depletion on Reservoir Seal Integrity: Geomechanical Model Application
Authors P. Schutjens, J. Ita, P. van den Bogert, F. Hermsen, P. Bakker, L. Watts, J. Webers and E. van den HeuvelFor a safe and efficient reservoir development, it is important to understand if, how, when and where faulting and fracturing will occur as a function of reservoir production or stimulation operations, or in case of a dumpflood or an internal blow-out situation. This paper describes 1) the making of a numerical geomechanical model to achieve this understanding, 2) the uncertainty in geomechanical model results, and 3) how the model results were applied in operational decisions for production and on reservoir fluid containment. The case study presented here is one of deep-gas production from stacked thin (few meters) sandstone reservoirs vertically separated by shale layers and laterally cut by steeply-dipping sealing normal faults, with pore pressure differences of several MPa across the faults in many sand-shale and sand-sand juxtapositions. We calculated the effective normal stress (σn) and maximum shear stress (τmax) along the faults and in the country rock as a function of pore pressure changes documented in the field development plan. The σn - τmax data were compared with fault slip and fracture-opening criteria based on Mohr-Coulomb frictional slip and tensile fracturing laws using fault cohesion, fault-friction-angle, and tensile strength as input. The geomechanical model results indicate that the current operational criterion of a maximum pore pressure difference of 7 MPa across the faults can be increased to 10 MPa without creating shear failure or tensile fracturing. This would lead to greater operational flexibility, cost reduction (less wells), and accelerated yet safe production.
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Modeling Tectonic Heat Flow and Source Rock Maturity in the Rub' Al-Khali Basin (Saudi Arabia), with the help of GOCE Satellite Gravity Data
Authors R. Abdul Fattah, S. Meekes, J. Bouman, J. Ebbing and R. HaagmansA 3D basin modeling study was carried out to reconstruct the regional heat flow and source rock maturity in the Rub’al-Khali basin. Gravity gradient data from the GOCE satellite were used to model deep structures, such as the Moho interface. Tectonic heat flow was modeled using the GOCE-based Moho interface to reflect heat flow variations in the basin though time and space. The thermal maturity of Silurian and Jurassic source rocks in the Rub’al-Khali was calculated using the GOCE-constrained basal heat flow model. GOCE-based Moho depth map was calibrated to data from known seismic stations in the region. This map provided input to constrain the heat flow in eth basin. Modeled heat flow values are consistent with known values of heat flow in the region. The model indicates that the Silurian and Jurassic source rocks are generally in the hydrocar-bon generation window and the modeled maturity trends are in agreement with the observations in the area.
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Applying 3D Close the Loop and Probabilistic Seismic Inversion Techniques on the Tibr Asset in Petroleum Development, Oman
Authors M. Scholten-Vissinga, C. Chockalingam and G.M TillerIn Petroleum Development Oman (PDO), a seismic driven 3D Close the Loop workflow has been successfully applied for the first time to the Tibr asset. The business objective was to delineate channel sands with challenging rock properties at a relatively deep target by better predicting the distribution of sands and shales within the Upper Gharif and Al Khlata reservoir sequences. As a result, we were able to reduce subsurface uncertainties leading to improved reserve estimates. 3D Close the Loop workflows allow for better predictions of layer thickness, reservoir properties and velocity away from the wellbore by optimal integration of seismic amplitudes with all other reservoir data. A pre-existing static reservoir model describing reservoir properties through geo-statistical algorithms served as main input. Rock and fluid property models were derived from existing well data. By relating reservoir properties such as net-to-gross, porosity and hydrocarbon saturation to acoustic properties, the 3D model s were converted to a synthetic seismic volume, which could then be compared to measured seismic data. In the final stochastic inversion, reservoir properties were updated until synthetic and seismic data matched within an acceptable error range defined by the signal to noise ratio.
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Integration of Petrophysical SCAL Measurements for Better Understanding Heterogeneity Effects in Carbonates: Case Study Using Samples from a Super Giant Field in Abu Dhabi
Authors S.S. El Din, M.R. Dernaika and Z. KalamCharacterization of carbonate reservoirs is challenging as well as daunting due to the inherent heterogeneities that occur at all scales of observation and measurement. Heterogeneity in carbonates can be attributed to variable lithology, chemistry/mineralogy, pore types, pore connectivity, and sedimentary facies. These complexities can be related to processes controlling original deposition and their subsequent diagenesis. Reservoir cores from super giant producing carbonate field in Abu Dhabi have been used in this study. X-ray CT scanning, Thin Sections, porosity, permeability, mercury-derived drainage capillary pressure (Pc) and pore throat size distribution (PTSD) have been used to define the petrophysical groups and different sedimentary facies. The effects of carbonate heterogeneity on reservoir behavior have been studied by correlating rock structure/texture and pore-throat size distribution to formation resistivity factor, cementation exponent (m), and to relative permeability. The effects of wettability and rock nature have been discussed based on the relative permeability trends observed on the main rock types covered in the field. Less heterogeneous reservoir rocks with muddy structure and uniform pore throat size distribution (PTSD) have moderate poroperm characteristics and tend to be less tortuous with average cementation exponent m at 1.85. More heterogeneous rocks with grainy/muddy or grainy structures and bimodal/heterogeneous PTSD have very good poroperm characteristics and tend to be more tortuous with range of cementation exponent m values from 2.20 to 2.50. Large variations have been obtained in imbibition relative permeability curves among the different rock types, which were explained on the basis of rock structure, PTSD curves and poroperm characteristics. The more heterogeneous rock types present more oil-wet behavior than the less heterogeneous rock types. The full integration of resistivity and phase flow laboratory results with geological heterogeneities showed consistent trends in reservoir characteristics, and offered in-depth understanding of the reservoir rock properties for potential investigations in further field development using IOR/EOR techniques.
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Bridging the Gap Between Thermal Modeling of Sedimentary Basins and Potential Fields Modeling: Using Geophysics to constrain Hydrocarbon Charge Models In Data-Poor Frontier Areas
Authors L. Kennan, N. Kuznetsova, M. Spaak, E. Hafkenscheid, O. Meuric and O. Podlaha and E. BiegertWe integrate subsidence, thermal, and potential fields modelling in a single, unified workflow which reduces the propagation of uncertainty when building geological models of data-poor frontier areas such as deepwater continental passive margins. Subsidence analysis is combined with a model for the relationship between mantle melting and lithosphere stretching and resulting isostatic equilibrium to estimate crust thickness and type and the temperature and density of the crust and underlying mantle in the past and at present. The results can be compared to observations, including potential fields such as gravity in addition to well data if this is available. The integration of potential fields and thermal modelling is particularly important in frontier areas where well data is sparse to absent and conventional calibration data (T, VR) is not available to basin modellers. Our methods have been applied to a number of circum-Atlantic margins, allowing us to build basin scale play concepts and hydrocarbon maturation and charge models with greater confidence and guide exploration decision making.
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Advanced Satellite InSAR Technology For Fault Analysis And Tectonic Setting Assessment. Application To Reservoir Management And Monitoring
Authors A. Tamburini, S. Del Conte, A. Ferretti and S. CespaHydrocarbon reservoir operation, i.e. fluid extraction and injection, are responsible for volumetric changes of reservoir itself resulting in surface deformation phenomena (subsidence or uplift). This processes are controlled by the tectonic framework which is responsible for reservoir compartmentalization and/or fault reactivation. Monitoring surface deformations can provide valuable constraints for modeling the dynamic behavior of a reservoir and help achieve more effective reservoir exploitation with obvious economic benefits. Advanced satellite interferometry represents one of the most valuable and cost-effective techniques, capable of providing high precision and high areal density displacement measurements over long periods of time.
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Improvements of Sampling and Pressure Measurements with a New Wireline Formation Tester Module in Carbonate Reservoirs
Authors K. Cig, H.I. Osunluk, R. Naial, T.M. Ihab and A.Y. Al BaloushiA multilayer hydrocarbon reservoir in Abu Dhabi land is in an appraisal stage before experiencing an extensive field production operation. The hydrocarbon reservoir, having medium to low permeabilities, consists of a number of carbonate layers with their associated oil-water contacts. One of the challenges is to sample hydrocarbons in tighter layers as well as to measure valid reservoir pressures to determine oil-water contacts. While the goal is to accomplish the objectives with wireline formation testers (WFT) in openhole conditions, stationary times during logging are limited due to wellbore conditions. The time limit has been a longstanding challenge in the layers having especially lower permeabilities (<1md). A typical sampling operation involves advanced modules of WFT including a Dual-Packer and an Insitu Fluid Analyzer to identify fluid types and provide downhole compositions with densities. Reservoir pressures are measured generally with Single-Probe modules. The new WFT inlet module is introduced first time in Abu Dhabi across the carbonate formations to accelerate the stationary operations. The new inlet module showed an improvement over a Dual-Packer and a Single-Probe modules in several aspects: (1) Stationary times during sampling are reduced due to very low interval volumes in comparison to a Dual-Packer module and up to 60% faster oil breakthrough times are achieved. (2) Tight zone pressures are measured as fast as a Single-Probe module with lower supercharging effects. (3) Set and retract times are shortened so that a new sampling method of a set-retract-reset is developed without exceeding stationary times. This paper summarizes the recent achievements by reducing risks associated with long stationary times. The field benefits are demonstrated in two separate WFT operations by comparing data qualities and job efficiencies in the same reservoir layers. Results show faster sampling, more accurate pressure and permeability measurements in the carbonate reservoir.
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A Joint Shell / ADCO Development of a Shared Earth Model (SEM) to Support Further Development of a Giant Field, Onshore UAE
Authors B.D. Meyer, R.A. Nieuwenhuijs, R. Bennett, J.F. Brint and A. VizamoraThe field is located onshore Abu Dhabi and has been in production for more than 50 years. It covers an area of approximately 1500 square kilometers and has 20 reservoirs with producible hydrocarbons comprising a series of stacked oil and gas reservoirs with differing drive mechanisms and development maturity, including in-field exploration targets. This paper describes the work undertaken to build a full field Shared Earth Model (SEM) to support future drilling to maximize the field recovery and extend the field lifetime. The key business deliverable for the SEM was to allow more effective assurance of planned well trajectories in a highly congested surface/subsurface environment, thus increasing the safety of such operations. As a consequence, the SEM had to extend from ground level to the deepest penetrated reservoirs. The reservoir model is constrained by more than 70 seismic horizons and by more than 40,000 well markers of various vintages; this alone represented a significant modeling challenge. Automated QC & QA workflows were used heavily to analyse the input data and the model during each of the model construction iterations. The reservoir units are faulted but these faults do not extend to the surface. Due to limitations in the representation of such faults in pillar grids and a lack of continuity of fault interpretations from one reservoir to the next, it was decided to represent faults as properties and not as fault planes. This not only allowed adjustment per reservoir, without requiring a rebuild of the whole structural model, but also identified clearly a zone of uncertainty around the predicted faults, assisting well planning efforts. A major focus of the project was to provide an evergreen model which could be kept up to date with ADCO’s substantial drilling program. Therefore considerable effort was made to hand over not just a model, but also training in the key workflow’s and work practices which would ensure that ADCO staff have the skills in house to update and maintain the model. This was achieved through extensive use of Petrel workflows, which enabled quick & structured model updates and through several training sessions in Abu Dhabi, run over 3-4 days. This proved to be an effective mechanism to hand over the model and workflows to ADCO staff.
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From Feasibility to Processing: A Time-Lapse Seismic Experiment On Al Khalij Field – Offshore Qatar
Authors B. Pagliccia, F. Cantin, E. Brechet, E. Brosille, B. Blanco, P. Charron, M. Emang and M. RadigonTime lapse seismic survey (aka 4D seismic) is a geophysical tool used by the industry to guide and maximize field development. It has been proven successful mainly in clastic deposits environment (Gulf of Mexico, Gulf of Guinea, North sea,…) but sparsely tested on carbonate fields because of seismic quality concerns. Total E&P Qatar engaged in 2012 a “proof of concept” 4D pilot study on its operated Al Kahlij field – offshore Qatar- to demonstrate the value of information provided by a 4D seismic in a middle-east carbonate field under development. This study is made of: A feasibility study which aims to quantify the expected 4D effect by using a petro-elastic model and several chosen depletion scenarii. These input data are used to compute a synthetic time-lapse seismic dataset through a massive seismic modeling. A 4D pilot seismic survey shot in summer 2012 (monitor) which was designed to repeat the first seismic survey shot in 1998 (base). A dedicated seismic processing of both base and monitor in Total’s 4D processing dedicated center followed by a specific inversion process (time warping) to extract the awaited 4D signal. The main objective on Al Khalij field is to validate that 4D seismic is able to calibrate the reservoir model and make it more predictive. If successful, the time-lapse seismic survey concept can be envisaged for other carbonates field in Qatar and in the Arabic Gulf area for field development optimization.
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Moving Beyond Real-Time Operations Centres
Authors M. Laurens and M. KalesThis paper presents Shell’s platform designed and developed to support advanced drilling technologies and workflows. The capabilities supported by this IT platform are real-time performance optimization, remote control for directional drilling and measurement while drilling, completions and drilling automation. These are modular capabilities and can be combined to suit local requirements. The underlying IT platform has been developed to support each of the technologies and any of their combination. With this IT platform in place, the traditional RTOC model changes as new functionalities like remote operations and automation are added and the scope is extended to include monitoring of low complexity and low cost wells drilled in unconventional plays.
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Statistical Analysis for Partial Inspection of Heat Exchanger Tube Bundles
Authors M. Alathba, R. Jones, N. Laycock, F. Hoeve, A. Ostrowska, S. Terpstra and S. KuniewskiThe Pearl GTL plant in Qatar is the largest Gas-To-Liquids plant in the world, located north of Doha in Ras Laffan Industrial City. Like any other plant, it has to be maintained carefully, with the right tools and technology. During the forthcoming major turnaround, there is a need for the planned inspection of more than 60 shell and tube heat exchangers, with a total of more than 40,000 tubes. With the obvious desire to minimize the total shutdown cost and duration, it is desirable to only inspect the minimum fraction of the tubes that is necessary to determine their condition with a degree of confidence that is consistent with each individual item’s criticality in terms of both safety and production. Statistical data analysis, and in particular a range of techniques based on Extreme Value theory, are an important tool that can assist in this endeavour. In general terms, there is increasing interest within the Oil and Gas industry in the use of statistical methods in asset integrity management, and one major area of application is the planning and evaluation of inspections. The potential benefits from applying these techniques are seen to include more effective management of the risks associated with in-service degradation and, although the techniques have been around for some time, these methods are gaining traction in the industry now that the latest inspection technologies make available more quantitative information. Indeed, statistical analysis is already a fundamental part of some aspects of integrity management; for example, it is a key requirement of the HOIS approach to NII.
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Application of Digital Core Analysis (DCA) and Pore Network Modeling (PNM) based on 3D Micro-CT Images for an EOR Project in a Mature Oil Field in East Malaysia
Authors W. Nur Safawati Bt W Mohd Zainudin, Z. Md Zain and L. RiepeFor the planning of an EOR project in a major mature oil field in East Malaysia, an extensive Routine and Special Core Analysis (RCA/SCAL) programme has been performed on unconsolidated clastic reservoir rocks. In view of the limited availability of homogeneous core plugs of suitable size for core flooding experiments and for “conventional” SCAL laboratory investigations, a complementary analysis of petrophysical properties was performed based on the acquisition of high resolution 3D Micro-CT (MCT) images, that are used to identify homogeneous sub regions of plugs, and to exclude zones that were damaged during coring. From these regions of undisturbed zones, reliable static reservoir parameters are derived by application of Pore Network Modeling (PNM) techniques. In addition to the generation of “static” parameters (e.g. porosity, permeability, grain size and pore size distributions), PNM simulations of primary drainage and imbibition, and the resulting pc and Krel curves were undertaken. The 3D MCT images were complemented by Fluorescense Microscopy and Field Emission Scanning Electron Microscopy (FESEM) investigations to visualise at a higher resolution possible effects of wettability changes due to cleaning, restoration and flushing of the cores. Variation of the residual oil phase distribution (ROS) due to wettability changes during the cleaning and core handling processes were observed. In view of the planned immiscible Water Alternating Gas (iWAG) process to increase the recovery, water injectivity tests and formation damage (FD) studies were performed in the lab. Potential causes for formation damage (e.g. changes in pore morphology or blocking of pore throats due to fines migration) were visualised by comparing registrations of MCTs at different stages of the flooding and FD experiments. The application of 3D MCTs and PNM proved to be a unique new option to visualise and understand the sensitivities during the handling of cores, and to quantify potential effects of the experimental procedures on the multiphase flow in conventional flooding experiments. As such the Digital Core Analysis and PNM technology is a very quick and robust complementary alternative for the optimised investigation of EOR options, especially in cases where conventional laboratory investigations are limited due to time constraints or due to the status of the core material and resulting potential experimental artefacts.
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Interference Testing of Horizontal Producers and Injectors in the Huntington Field
Authors O.R. Nurafza, B. Al-Shamma and W.C. FengThis paper describes the design and interpretation of interference tests conducted between injectors and producers in the Huntington oilfield. The field is located in the UK Central North Sea and developed with four horizontal producers and two inclined water injectors. Water injection provides reservoir pressure support and mitigates the uncertainty of aquifer strength and its connectivity to the oil leg. This ensures adequate pressure maintenance in support of hydrocarbon recovery. It is important to understand effective communication between the wells. This is required to improve the forecasts of water breakthrough, to plan preventative actions and to optimise field operations and reservoir management. Therefore, a series of modified pulse tests were performed during the clean-up and well test campaigns to minimise disruption and delay to the drilling schedule. Data were recorded using permanent down-hole gauges installed in the horizontal producers, and the analyses of the results were performed using both analytical and numerical models. The modified pulse tests confirmed good communication between the producers tested. A reasonable match between the modified pulse test data and simulation model predictions is demonstrated in this paper, where reservoir properties such as permeability and porosity estimated for the inter-well areas show good agreement with the well test results. The test between injector and producer was also used to match the pressure response and can be used to predict injection water breakthrough. In the test, water was injected into two different intervals, the Upper and Lower Forties. Comparison of the injection test results with numerical simulation data suggests that no communication exists between these two intervals. This is a practical example of interference testing which provides insight and assurance on effective reservoir properties on an inter-well scale. This kind of data, before field start-up and free from the influence of other producers, is very useful for the field performance prediction and also rarely available in the literature.
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Process Safety Management - a Prerequisite for Sustainable Gas Production
More LessThe LNG industry enjoys a commendable track record in reliability and safety. There is however no reason to be complacent, as we can learn from various major hazard accidents across the energy industry (e.g. Piper Alpha, Texas City, Macondo), which regretfully resulted in fatalities, asset damage and had environmental impact. LNG operations may be similarly vulnerable to major incidents if hazards are not properly managed. Root causes for major accidents are often complex in nature. They are related to a series of interlinked failures in mechanical, human judgment, engineering design, operational implementation and team interfaces. To avoid such incidents, we must translate learning into effective barriers, aimed at reducing risk to acceptable levels. This article will share some insights on how this is done in Shell.
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Conditioning of a Carbonate Reservoir Model Using Seismic data in an Offshore Upper Mishrif Field in the Middle East
Authors K. Budkina, K. Philippe, M. Emang, E. Fetel and T. PigeaudThe studied reservoir, a large mature offshore Middle Eastern field, producing from Upper Mishrif limestone series, shows strong heterogeneities (vertical and lateral), due to the original properties of the sedimentary facies and the effect of several subsequent phases of diagenesis and fracturing. This results in complex dynamic field behaviors, which can be difficult to predict including strong saturation variation in the long transition zone, localized dual porosity/permeability flow, early water breakthrough, strong water-cut and uneven/non-uniform pressure support. In order to better predict & optimize future production and/or support additional developments, a robust reservoir model integrating all available data (geological, geophysical and dynamic) is clearly needed. This paper focuses on two key steps in geo-model construction: facies and porosity modeling and more specifically on the use of seismic data for reservoir characterization while taking care of over-utilization. Aims are to improve model reliability and prediction capabilities. Facies and porosity modeling was constrained by numerous data from cored exploration vertical wells and horizontal development wells. Initially reservoir facies represented by eight “electro-facies” are distributed according to the available well data and proportion maps derived from regional knowledge. Then porosity is populated within each facies with dedicated distribution and honoring well data. In parallel, a 3D pseudo-porosity cube was generated by applying the strong linear correlation observed between acoustic impedance and well porosity to an acoustic impedance dataset resulting from a post-stack inversion. It serves as an additional large-scale constraint for modeling: the vertical resolution of the pseudo-porosity cube is roughly 15 meters, while facies and porosity changes occur vertically within 3-8 meter thick layers as described from the well data, it extends over most of the field. It is integrated (1) as a direct soft trend for porosity and (2) as qualitative check of the final geo-model. Once porosity is modeled; it is converted into pseudo-impedance and a synthetic seismic dataset for comparison with original data. In addition the pseudo-impedance was compared to the acoustic impedance cube resampled at reservoir model scale. Both allow significant seismic-scale inconsistencies to be easily detected and understood for further iterative correction. Once areas and origin of mismatch between seismic data and the geological model were identified, reservoir model porosity, and consequently facies, had to be locally modified to ensure consistency with geophysical information. The modified reservoir model porosity was then used to regenerate a synthetic seismic data and compared to the original seismic data in order to check if the modifications were sufficient to obtain optimum coherency between all data. This kind of feedback loop is an efficient iterative process, a time-consuming but necessary step for relevant geo-model quality control. The consistency between all available geological and geophysical information gives high confidence in the result, and ignores seismic noise. It ensures the robustness of the geological model and consequently ensures a sound basis for dynamic modeling.
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Methodology and Implications for Natural Fracture Network Modelling in a Carbonate Reservoir of Abu Dhabi
Authors M. Sirat, X. Zhang, G. Xi, Q. Ni and A. Mohamad-HusseinTo optimize the areal and vertical sweep efficiency in a fractured carbonate reservoir of Abu Dhabi, 3D coupled reservoir geomechanical modelling is carried out, investigating the impact of natural fractures on reservoir deformation and performance in future production. In this study, AntTracking, Neural Network and fracture simulation techniques were used to model natural fracture networks by integrating FMI image logs, petrophysical and seismic data. The seismic data were smoothed to improve signal-noise ratio by removing noise. Based on smoothed seismic cube, variance processing was performed to enhance the edge effect, followed by AntTracking processing to enhance the discontinuity. SDPs (Seismic Discontinuous Planes) were extracted from AntTracking for the carbonate reservoirs representing fractures including faults and joints. The extracted fractures were validated against FMI interpretations of 11 wells in terms of orientation and intensity. To further validate the developed fracture model, the identified fracture sets were calibrated against the geological structures in the field, such as the main anticline and major faults. Four fracture groups were identified. Three groups of fractures were created in an early tectonic event associated with Oman stress, during which the main folding structure was generated, including (a) NW-SE trending related to R shear, (b) NNW-SSE and NNE-SSW trending related to R’ shear, and (c) WWS-EEN and WWN-EES related to P shear. Another fracture group identified from AntTracking volume is NE-SW trending, which was possibly associated with the same early event associated with folding and/or due to Zagros stress forming later tensile fractures. The fracture model was incorporated in 3D coupled geomechanics simulations and the impact of the presence of the natural fracture networks on the in-situ stress state, bulk Young’s modulus, bulk permeability and wellbore stability were investigated. It is concluded that highly deformable zones of the upper and middle reservoirs are generally clustered in NE-SW (maximum horizontal stress) direction. Better productivity is expected to place horizontal wells in this direction. The deformability of the lower reservoir is very different from the shallow reservoirs and has high deformable corridors oriented in NW-SE (minimum horizontal stress) direction. Better productivity is expected to place horizontal wells in this direction. In addition to productivity, the results also suggest that drilling horizontal wells needs to consider the presence of fractures and stress direction. It is recommended to drill horizontal wells towards the minimum horizontal stress direction. Drilling in this direction is more stable and less wellbore failure is expected.
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Geologically Guided Prestack Depth Imaging - a Case History From Greater Burgan, Kuwait
Authors K.M. Hafez, P.K. Mukherjee, M. Anandan, A. Al-Ghareeb, W.H. Abdul, A. Zahran, T. Saleh and C. CunnelPrestack depth migration (PSDM) can provide superior seismic volumes even in areas of low relief structures. A pilot PSDM study over the Greater Burgan oilfield in Kuwait demonstrated not only the uplift versus prestack time migration (PSTM), but also pointed to areas of further improvement in the velocity model building workflow. A full field (FF) study was subsequently performed, and incorporated the lessons learned from the pilot. The main area for enhancement was the integration of geological information into the velocity model. This included near-surface velocity characterization and incorporation of existing 3D log-based velocity models into the initial PSDM model, plus implicit geological constraints during the model updating workflow. The results were a more geologically plausible velocity model with enhanced imaging versus both the legacy PSTM and pilot PSDM volumes, establishing the FF PSDM volume as the main seismic volume for interpretation, well planning and reservoir characterization for the Greater Burgan field.
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Developing disruptive and revolutionary new generation seismic technologies for the Middle East
More LessWe present the business and technical underpinning for developing revolutionary onshore and offshore seismic acquisition technologies in order to meet the challenges of the new E&P business portfolio. In this paper we will also describe new seismic acquisition systems developed with external technology partners and report their progress. These new systems aim at disrupting both the onshore and offshore seismic industry by delivering accurate and high quality seismic data with significant cost improvement. For land Shell is pushing toward a million channel system development in order to drastically drive the cost down with high receiver and source efficiency, and strongly improve the seismic quality with WAZ, long offsets, and broad bandwidthfor surface seismic. This system also targets permanent reservoir monitoring. For offshore applications, a multi-source fast deployed ocean bottom node (OBN) system is being developed to drastically reduce the survey cost such that it can be cost effectively applied to large exploration surveys as well as higher resolution surveys for 4D. Shell expects to commercialize these new technologies with partners in order to deploy them to Shell assets in the nearer term and to the industry in the longer term.
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Nitrified Water as UBD Medium - Perfect Recipe for a Corrosion Nightmare: Issues and a Solution
Authors I. Hussain, D. Al-Enezi, A. Al-Khaldy, S. Sulaiman and S. HayatKuwait Oil Company embarked on an ambitious project to look for gaseous Hydrocarbons in a hitherto un-proven formation in the North Kuwait Field. As the target formation was extremely depleted and usually was drilled through under-total-loss conditions, these wells were designed to be Under-Balanced-Drilling (UBD) wells. The design conditions for an Under-balance or drawdown of 10% below formation pressure of the target zone called for Nitrified water as the fluid medium. Design simulations showed a normal Nitrogen pumping rate of around 1100 scfm for maintaining the UB conditions. Further testing of the target formation called for a huge drawdown of a maximum of 30%. This led to extreme conditions of pumping Nitrogen at the rate of 2000 scfm. The normal operating conditions with membrane NPU resulted in 5% Oxygen being pumped in with Nitrogen. This resulted in a highly corrosive environment under Bottom-hole conditions, especially when we started producing highly saline formation water. The above conditions led to very severe corrosion of our Drill string and UBD Coring equipment, creating a potential hazard of losing our whole string. Conventional corrosion inhibition completely failed to arrest the corrosion of the string. This led to intensive study and debates within the team to find a solution to the problem and quickly too. A multi-pronged solution comprising of controlling pH, usage of Phospate Ester Inhibitor formulation, filming amine and monitoring through usage of Corrosion coupon rings in the drill string led to a dramatic improvement of the corrosion damage. Corrosion hazards in UBD wells are a reality and a heady-mix of ideal conditions for corrosions could mean disaster. Conventional Corrosion programs usually fall short of dealing with the severe corrosion existing down-hole. Special operations such as Underbalanced Coring could fail dramatically before achieving objectives. A multi-pronged approach needs to be designed and the severity of the problem understood before embarking on such ambitious projects. The authors are going to present a strategy for putting the best foot forward when dealing with such issues. Being forewarned will always mean being forearmed.
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Application of Technologies for Improved Drilling, Hydraulic Fracturing, and Production Increase – Case Studies from Deep and High Pressure Gas Wells
Authors Z. Rahim, H. Al-Anazi, A. Al-Kanaan and W. El-MoftyIntegration of technologies and application of innovative practices in drilling, completion, acid stimulation, and hydraulic fracturing have significantly contributed to the successful development of tight gas reservoirs. The well planning and development procedures entail careful selection of several critical parameters such as drilling azimuth, lateral length, well trajectory, drill-in fluids, well completion methods, stimulation fluid properties, fracture placement technique, proppant types, treatment volumes, and pump schedule. All of these critical parameters impact fracture dimension, proppant transport and placement, as well as stimulation efficiency and effective post-frac clean-up. Depending on the reservoir rock properties and stress profile in the near wellbore (NWB) and the far field, the effectiveness of hydraulic stimulation (fracturing or matrix acidizing) in connecting the wellbore to the undamaged virgin reservoir, as well as maximizing reservoir contact (RC) area and enhancing flowback of treatment fluids to restore proppant conductivity, dictate the well potential, sustainable gas rate level, and ultimate recovery. Successful fracture stimulation is therefore, measured not only by proper pumping and placement of the designed treatment, but more importantly by the post-treatment stabilized production rate after the well is cleaned up and flowed back. Due to the diverse nature and characteristics of Saudi Arabian reservoirs producing rich gas from deep, high pressure and temperature formations, drilling and fracture treatment parameters, procedures, and methodologies are continuously being improved to obtain even better results. Based on reservoir properties and production expectations, this paper summarizes the collaborative approaches undertaken to carefully select candidates, drilling plans, completions, and fracture treatment designs, thereby providing a real example of how reservoir management, petroleum engineering, drilling and technology work in harmony to achieve the ultimate goal—high rate wells, sustained production, high rate of return, and expeditious payback. This rigorous process includes important factors, such as real-time geomechanical modeling to predict the correct mud weight window and borehole stability issues while drilling long laterals toward the minimum horizontal in situ stress ( min) direction.7 Selection of a completion system to effectively fracture stimulate the well and place acid or proppant in multiple stages, and use of stimulation fluids that are compatible with the reservoir rock, cause minimum damage to the proppant, and enhance clean up without compromising the ultimately desired fracture dimensions are among the most important elements of this process. Engineered pump schedules have proven advantageous in minimizing premature screen outs that can often happen in high-stress tight reservoirs. This paper shows how proper well planning is important for successful fracture treatment and increased production.
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Ordovician Source Rocks and Devonian Oil Expulsion on Bolide Impact at Siljan, Sweden - The Re-Os Story
Authors H.J. Stein and J.L. Hannah, G. Yang, R. Galimberti and M. NaliTo test the effectiveness of the Re-Os system for tracing source rocks and marking the time of maturation and expulsion, we examined a natural system in which key variables are controlled. Hydrocarbon source rocks (Late Ordovician Fjäcka shale) and adjacent, partly contemporaneous reservoir rocks (carbonate mounds) are exceptionally well exposed in quarries, drill core and outcrop in the Siljan area of central Sweden. At 377 Ma, a giant meteorite impacted the region heating Early Paleozoic sections, including immature Ordovician-Silurian hydrocarbon source rocks. Oil seeps and asphaltene coatings in carbonates just outside the Siljan impact crater attest to hydrocarbon maturation associated with the impact. The size of the impact supports elevated temperatures over a maturation-migration period of 10 to 1000 Ka, not unlike that for some sedimentary basins. The Siljan “field laboratory” permits sampling of source rock and migrated oils in immediately adjacent units – uniquely, with the time of maturation temporally pinned by the bolide impact. Through Re-Os analyses of the source rock and analyses of the oil it generated, we found the Re-Os isotopic system to be intact at two of three shale localities, obtaining the expected late Ordovician and early Silurian depositional ages. In contrast, the Re-Os isotopic compositions and erratically varying Os concentrations derived from the oil seeps suggest infusion of shale-derived oil with Os derived from the bolide. Thus, we show that shales generally retain their Os isotopic systematics, even under extraordinary circumstances, whereas small quantities of migrating oil at Siljan were easily overwhelmed by the strong Os isotopic signature carried by the bolide.
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Age and Composition of Source Rocks: New Steps toward Tracking Hydrocarbon Origin
Authors J.L. Hannah and H.J. Stein, G. Xu, R. Galimberti and M. NaliA variety of chemical fingerprints link migrated hydrocarbons to their source rocks, defining the ends of migration pathways. Rhenium (Re) and osmium (Os), redox sensitive elements concentrated in organic material, add unique information – time. Decay of 187Re to 187Os provides a radiometric clock measuring time since chemical closure of the organic material. Here we show that Re-Os geochemistry of source rocks defines the age of deposition and tracks environmental changes through time. This geochronometer also reduces ambiguity with a fingerprint for migrated hydrocarbons: evolving 187Os/188Os in migrated hydrocarbons, dependent on the 187Re/188Os ratio and age of both source rock and hydrocarbons, constrains models for the timing of migration. Black shales from the lower Streppenosa Formation, deposited in a deep euxinic intraplatform basin, yield a Re-Os age of 200.3 Ma and initial 187Os/188Os of 0.87. This Hettangian age aligns perfectly with the known biostratigraphic age, is nominally younger than the 201.3 Ma Triassic-Jurassic boundary[1], and postdates major magmatic pulses of the Central Atlantic Magmatic Province (CAMP, 201.6 and 200.9 Ma)[2]. Primitive CAMP magmatism produced sharp decreases in both 87Sr/86Sr and 187Os/188Os ratios of seawater[3], as both track relative inputs from continental versus chondritic sources. Osmium, however, has a much shorter seawater residence time than Sr; our data reveal that 187Os/188Os returns to high ratios within 1 m.y. of cessation of CAMP magmatism. High 187Os/188Os at 200.3 Ma documents reduced contribution of Os from CAMP, and may also reflect enhanced continental runoff from uplift along newly rifted margins. Osmium isotope variations in seawater, archived in organic-rich shales, provide a sensitive record of tectonic and environmental changes during source rock deposition.
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An Integrated Approach to Carbonate Karstic Reservoir Characterization and its Application to a Field Case in the Tarim Basin
More LessThe Lower and Middle Ordovician carbonate karstic reservoirs form an important type of reservoirs in the Tarim basin, the largest inland basin in China. Karstic feature characterization along with infill identification provides a great opportunity to delineate the distribution and connectivity of collapsed-cave systems. Based on carbonate karst concepts, this paper presents an integrated approach to characterize collapsed-cave systems and to map the geomorphology and distribution of karstic drainage components. Seismic amplitude and geometric attributes are used to identify karst features such as collapsed-cave complexes, conduits and infiltration or dissolution zones. A multivariate attribute classification technique is applied to generate karst seismic facies that highlight these features. Clustered karst features are sampled into the grid model to construct a 3D architecture model of collapsed-cave systems. This model eventually incorporates all clustered features, revealing their spatial distributions, inherent complex shapes and lateral connectivity. In the case of preserved collapsed-cave systems become disconnected and occluded as a result of infilling and roof collapsing, collapsed-cave systems need to be further calibrated in order to locate infill drilling and identify dynamic compartments. The seismic acoustic impedance attribute facilitates the identification of infill within collapsed-cave systems because chaotic breakdown breccias and cave-sediment fills have an impedance lower than that of the host limestone resulting in a significant impedance contrast. Incorporating the impedance attribute with the architecture model, the bodychecking technique is applied to searching for connected cells to extract karstic drainage components. The geomorphology and distribution of individual components can be mapped. Integrating reservoir production data and borehole imaging logs, the drainage components can be evaluated and sorted. The case study is addressed to illustrate applications of these technologies and their efficiency.
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Live Pressure Control Risk Analysis for Drilling Through Multiple Reservoirs
Authors H.C. Karlsen and T. NilsenIn 2010, a risk analysis taking into account both uncertainties in reservoir parameters and at the same time accounting for real time pore pressure measurements during a drilling operation on the Norwegian continental shelf (NCS), was completed. The plan was to drill through seven reservoirs, each independent of each other with a vast amount of uncertainties in the pore and fracturing pressure due to years of injection and production. The risk analysis was first made as an input to the drill plan, using best reservoir parameters available as well as expert judgments. Simulations were performed within a Monte Carlo (MC) framework. Results like for instance probabilities for fracturing and kick for drilling through the next reservoir(s) or tripping out, as well as an optimum mud weight for reducing risk, were obtained. The analysis was updated real time as the pore pressures were logged during the drilling phase, providing the best possible risk picture and giving the decision takers a possibility to update the drill plan before drilling through the next reservoirs. This paper describes how the main characteristics of the reservoirs were modeled and how the risk analyses were performed. Simulations obtained, both before and during the drilling operations, are presented. Results like the probabilities of fracturing and kicks as a function of reservoir parameters and number of reservoirs drilled, as well as optimum mud weight for risk reduction, are emphasized.
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Predictive Emission Monitoring System: Innovation in Measurement Technology
Authors C. Sadois, A. Suliono and P. Julien, M. Raja and K.A. Al-SulaitiPer State of Qatar environmental regulations, Continuous Emission Monitoring Systems (CEMS) are required to be installed on combustion units with a heat input capacity of greater than 25 megawatts (MW). CEMS are well regulated in US and European jurisdictions to monitor air emissions compliance. However, CEMS entail extensive calibration requirements and are difficult to maintain and operate in the harsh climate of the Arabian Gulf. Based on the challenges noted above, Qatargas Operating Company Limited (Qatargas) and TOTAL E&P Qatar (TOTAL) collaborated on a study to assess the viability of Predictive Emissions Monitoring Systems (PEMS) as a reliable and sustainable emissions monitoring technique. The first part of the study focused on the development of PEMS algorithms and comprised a blind benchmarking evaluation of the three main types of PEMS technologies (first principles, statistical and neural networks) using data collected from an operating Qatargas gas turbine. The second part of the study assessed the operational, maintenance and cost aspects of PEMS installation with reference to international guidelines. This paper summarizes results of the first part of the above study which includes the results of the technical, blind benchmarking comparison of PEMS technologies on the pilot gas turbines. These results suggest that PEMS measurements can be as accurate as that of CEMS. One of the advantages of PEMS, being a software based-solution, is the reduced requirement for installation of additional physical monitoring instrumentation, which translates into substantially lower capital and operational costs as well as reduced calibration and maintenance requirements. The findings of the second part of the study with regard to installation and operation of PEMS installations will be discussed in a future paper. PEMS have been successfully regulated in several worldwide jurisdictions, including by the USEPA. This paper aims to demonstrate that PEMS can be a viable emission monitoring tool as both an alternative and complementary capacity to CEMS.
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Crises Management in the Oil and Gas Industry
By G.C. OdemeneCrises are situations that disrupt systems, processes, and lifestyles. They adversely impact individuals, assets, prospects, operations, and reputations of organizations and societies on short and long-terms with significant environmental, social, economic, political, and legal consequences hence the need for priority attention to crises management. This study focused on crises in the oil and gas industry with special emphasis on the lingering situation in the Nigerian-Niger Delta between the communities, the oil and gas companies, and the Government. They became international concerns due to kidnappings, fatalities, assets destruction, environmental degradation, and poverty in the oil-rich region. Despite the industry’s substantial expenditure on security, kidnapping and vandalism persist as restive youths who feel marginalized, seek to hurt systems they believe, denied them quality life. Despite general knowledge and blames traded by parties involved, the study used qualitative-historicalnarrative- approach to interview representatives of communities, oil and gas companies, and Government to discover root causes of the crises. Coping theory by Lazarus and Folkman and crisis decision theory by Sweeny were utilized to understand the reasoning and responses of the people to the decisions and management strategies of the Government and oil and gas companies. Results revealed the root causes of the crises as specific policies and strategies of the Government and oil and gas companies, ethnic crises in the region, environmental pollution and degradation and failure to remediate polluted areas, lack of basic infrastructures, lack of human and infrastructural development, unemployment, and noninvolvement of the people in decisions affecting the region. Findings were used to develop recommendations to aid Government and Oil and Gas Companies on how best to stem crises and foster peace in their areas of operation. The enormous consequences discovered by the study provide crucial lessons for operators the world over and findings can be leveraged on to ensure appropriate and proactive crises management approach in the industry.
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Core Flood Analysis of Acid Stimulation in Carbonates: Towards Effective Diversion and Water Mitigation
Authors O. Gharbi, S. Goedeke, M. Al-Sammaraie, S. Al-Shahwani, P. Cheneviere, N. Al-Mohannadi and P. JulienIt is well established that acid stimulation in carbonates can enhance the productivity of oil and gas wells. As carbonate porous media are highly reactive in contact with acidic solutions, when acid is injected into carbonate reservoirs, the near wellbore region is subject to chemical dissolution. This is a reactive transport phenomenon, as acid is flowing and transported through a porous media. Coupled changes of the fluid and rock properties are taking place. Changes in chemical concentrations of the in situ fluids, the surface area, the permeability and porosity are also occuring. In this context, many studies have experimentally and numerically investigated carbonate acidizing. It has been shown that different dissolution regimes can be observed based on two main parameters, basically, the injection flow rate and the acid content. Wormholing i.e. a non uniform dissolution which is characterized by the creation of a conductive pathway along the porous media, is therefore observed for relatively high flow rates and low pH (high acid content). It also has been shown that for a certain pore structure, optimum injection rates, where the minimum acid volume leads to the highest permeability increase, (optimum wormholing) exist. Therefore, in field applications during acid stimulation jobs, the acid is injected at relatively high pumping rates in order to achieve an efficient zonal coverage and sweeping efficiency. Today, acid stimulation is widely used for newly drilled wells or wells that are experienced in production decline.
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Clad through Clad: A Mechanical Water Shut Off Solution for Commingled Production from Multilayered Reservoirs
Authors S. Bourgoin, M. Sobirin, A. Mahardhini, C. Nathanael and M. JonesA casing or tubing clad is a metal sleeve that can be run by several intervention means into a well to isolate an area of interest, be it to provide a permanent seal over splits, holes, or perforations in tubing and casing or for water shut off. Once it is on depth, the clad or metal sleeve is expanded out against the tubing or casing wall to form a seal. Taking the example of water shut-off isolation, conventional clad technology only permits a ‘bottom up isolation’, the current technology does not have the ability to pass through an expanded clad of the same size thus it is not possible at a later date to install a second clad below an existing clad. To resolve this issue, in 2006 TOTAL instigated the development of a “Clad thru Clad” technology through a JIP (Joint Industrial Program) Water Management R&D Project with Maersk, Statoil, Chevron, and BP as partners. Meta was selected to develop the clad through clad technology. The project objective was to design an electric line conveyed clad able to pass through other similarly sized clads previously installed in a well incorporating a metal-to-metal interference fit with elastomer seal against the 5-1/2” production casing or tubing wall. In addition to the dimensional, pressure rating (5000 psi absolute, 2000 psi differential) and temperature rating (125 degC) constraints, one of the major challenges was to achieve sufficient collapse rating for the clad once expanded. The Internal Clad™ is deployed using a hydraulic expansion system. The setting tool consists of a standard electric line cable head, an electronic section (consisting of gamma ray (GR), a casing collar locator (CCL), a motor control module and pressure sensors), a down-hole reservoir, hydraulic module (consisting of motor, a pump, an intensifier and valves), and the setting tool itself. The first trial was performed in Total Indonesia’s Peciko field; well C, a gas well producing from a multilayered reservoir. The field trial was SUCCESSFUL although a number of improvements for future operations were identified.
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Multi-zone Completion Design for Long Horizontal ERD Wells in Al Shaheen Field
Authors A. Balsawer, S. Hirani, P. Lumbye, A. Krog, V. Bonnell, M.R. Jaafar and I. Abul-HamdMaersk Oil Qatar AS, under the Exploration and Production Sharing Agreement with Qatar Petroleum, operates the Al Shaheen field, Offshore Qatar. In order to maximise recovery from the shallow and thin reservoirs, long horizontal ERD wells have been drilled in both, radial and line drive patterns with alternating producers and injectors. Recently, long horizontal wells pushing the limits of surface-controlled multi-zone completions in the reservoir were planned, drilled and completed. To achieve maximum reservoir contact, pre-drilled liners with open hole isolation packers were installed from the production casing shoe to TD (~6,800 ft to ~29,300 ft MDRT, ~3,450 ft TVDRT at 90° inclination) in multiple runs. The completion was installed to facilitate selective control of each of the 3 zones using surface controlled valves. The inner completion string was run to 22,985 ft by segmenting the completion string into 2 runs. This was achieved by having the lower section run on a drill pipe running string with a swivel to facilitate rotation of the running string to get to depth. The upper completion with multiple control lines was installed using floatation technique (~8,000 ft tubing length floated). One of the wells was subsequently acid stimulated using the Maersk Oil Patented controlled acid jetting (CAJ) technique. The objective of this paper is to share the installation experiences, detailed analysis, procedures used and lessons learnt completing these multi-zone wells. The paper also outlines procedures to establish initial conditions (using calculation spreadsheets to verify WellCat simulations), and then calculate all possible load cases expected during life of the well by using tri-axial design approach. A detailed analysis has been compiled to evaluate tubing length change, tubing-to-packer forces and casing-to-packer forces. The selective zone stimulation load case is analysed in detail. A detailed analysis of forces v/s limiting force envelopes for the tubing, packers and accessories for multi-zone completion has also been demonstrated.
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The Role of Regional Basement Fabric on Cretaceous Structural Deformation; a Case Study from Al Shaheen Field, Offshore Qatar
Authors V. Zampetti, L. Madsen, H. Cromie, G. Durance, M. Emang, N. Bounoua and T. GagigiThe giant Al Shaheen Field in Block 5 and Block 5 Extension, offshore Qatar, contains a stacked sequence of thin Lower Cretaceous reservoirs associated with a complex array of subtle faults which influence dynamic reservoir behaviour in certain areas of the field. A multidisciplinary analysis that integrates 3D seismic, well data and a regionally developed structural model indicates that at reservoir levels, deformation occurred in an incipient low-displacement (lateral and vertical) strikeslip dominated regime, characterized by a complex pattern of predominately steep to sub-vertical branching fault zones. Seismic interpretation and well calibration indicates two major fault zones trending WNW-ESE and NNWSSE, showing a dextral and sinistral sense of shear respectively. These fault zones are expressed as elongated depressions on structure maps and are formed by discontinuous arrays of en-echelon segments resulting in a spatial variability of fault distribution and behaviour. A secondary set of faults trending NW-SE and bounded between major WNW-ESE fault zones can be consistently mapped and is interpreted to represent either synthetic Riedel structures or normal faults. At deeper Permo-Triassic levels, continuous, well-developed fault lineaments are observed below the weaker Cretaceous lineaments. The interpreted deformation in the Al Shaheen Field can therefore be related to the development of shear zones associated with the reactivation of pre-existing deepseated Infra-Cambrian basement anisotropies during the Cretaceous Oman Alpine 1 and Tertiary Zagros Alpine 2 tectonic events. The proposed structural model of the Al Shaheen Field provides a key input and a further calibration area to constrain the tectonic evolution of Qatar and of the entire Arabian plate with regards to basin evolution, timing of structuration, structural style and faults and fractures distribution on both regional and field scales.
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Collaboration and Smart Fields - Experience from Global Scale-up
Authors F.G. van den Berg, G.A.R. McCallum and M. GravesShell’s Smart Fields programme has built elements of Intelligent Energy into the key field developments over the past ten years. Considerable value has been achieved, from new technologies, new ways of working and global implementation. In Shell, Collaborative Work Environments (CWEs) have been implemented on a large scale, mostly focusing on the production and field surveillance area and on the real time drilling monitoring. More recently, collaborative work environments have been set up to streamline field development planning. The environments have provided significant benefits to the assets, by enabling new ways of working, improved communication and faster decision making. Shell and Wipro have teamed up to establish a flexible, global, large scale implementation programme. Gradually, the programme has converged on standard solutions and designs for processes and technologies and on a lean implementation methodology. Strong focus has been placed on embedding the changes into the organisation. Enticing field teams to adopt and keep new ways of working has required some inventive methods and intensive coaching of staff at all levels.
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A Novel Chemical Sand and Fines Control Using Zeta Potential Altering Chemistry and Placement Technique
Authors P. Singh and R. van PetegemSand and fines production is one of the oldest problems in the petroleum industry and one of the toughest to solve. Today, many technologies and methods exist; in some cases some sand and fines production is manageable, while for others it cannot be tolerated at all. Also, many wells do not produce sand or fines from the onset and may not require an active sand control solution until later in their lives. Sand influx into the wellbore may lead to various down-hole and surface problems. Chemical sand control solutions have been around for many years and have always been attractive due to their ability to be installed without any restrictions to the well bore geometry. However due to the difficulties with placement, and in many cases their association with formation damage, there have been reservations regarding the use of chemical methods as a standard sand control method. This paper presents a unique and novel chemistry that increases the maximum sand/fines free rate without a significant reduction in permeability and discusses the placement techniques essential for a successful application. It includes a review of laboratory tests, treatment design considerations and study of some wells that have been treated with zeta potential altering chemistry.
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Oil Production Optimization in an Integrated Digital Field: The KOC Burgan Pilot Project Experience
Authors A.K. Al-Jasmi, A. Choudhuri and D. JoyKuwait Oil Company (KOC) launched the Kuwait Integrated Digital Field GC1 (KwIDF-GC1) pilot project in 2009 as an investigation into how a cross-functional and cross-domain infrastructure could be established to aid in the achievement of corporate goals set for the following two decades. The company’s vision for 2030 includes a philosophical shift in the way that the country’s workforce accomplishes its tasks, employing the latest technologies and work processes. The project solution integrates field instrumentation, workflows automated in software, and focused collaboration. The Burgan oil field, the second largest in the world and the largest clastic reservoir, was discovered in 1938 and commercial oil production from it began in 1946. Production peaked in 1972 at around 2,400,000 barrels per day, and declined to around 1,700,000 barrels per day by 2005 [Croft 2013, Cordahi and Critchlow 2005]. Management of the reservoir has become increasingly challenging, partly due to damage that was incurred as the Iraqi invaders set fire to the wells during their retreat in 1991. This project is a first in the State of Kuwait to instrument oil wells with pressure and temperature gauges, multiphase water cut meters and remotely automated chokes. Automation of the field was the first step in providing the advanced technology required of this project, realizing tangible advantages in minimizing the health, safety and environmental (HSE) exposure of field personnel. Wellsite data can be read, and choke positions can be set, remotely at the gathering center without the need for field personnel to enter hazardous areas. Work processes were converted into automated digital workflows supported by advanced network modeling and nodal analysis software in a state-of-the-art collaboration center. The collaborative teams use optimization and visualization software to contribute in real time to production operations that optimize production gains. Integration of multidisciplinary teams such as field development, sub-surface, production operations and maintenance in a real-time work environment enables proactive and reliable decisions to be made much more quickly than in traditional environments with disparate work teams. This paper describes how the various technologies and work processes are used by the collaboration teams during the pilot project to increase efficiencies in oil production.
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Detecting Asphaltenes by A Miniaturized Electron Paramagnetic Resonance (EPR) Sensor
Authors X. Yang, M. Tavakkoli, W. Chapman and A. BabakhaniAsphaltenes precipitation has become a major issue in oil production. It can clog oil wells and increase the cost of production. The precipitation can occur in the near-wellbore region, inside the wellbore, in subsea flowlines, and in the separator. Currently, there is no effective solution for monitoring asphaltenes concentration and precipitation in real time. In this work, we propose a novel method for monitoring asphaltenes concentration in crude oil, utilizing the physical principle of Electron Paramagnetic Resonance (EPR). The phenomenon of EPR is based on the interaction of electron spins with electromagnetic fields in the presence of an external DC magnetic field. As asphaltenes have paramagnetic centers, they generate EPR signals that can be measured with our proprietary EPR sensor. The sensor is implemented in a 0.13μm SiGe BiCMOS process technology. The sensor chip can operate in both continuous wave (CW) and pulse modes. The frequency is tunable from 770MHz to 970MHz, corresponding to Zeeman magnetic fields from 28mT to 35mT for a free electron. The chip consists of a voltage-controlled oscillator, a power amplifier, a low-noise amplifier, a down-conversion mixer, baseband amplifiers, and a pulse generation block. The EPR sensor uses a loop-gap resonator built on a PCB board to interact with the sample. The measurement results of the asphaltenes samples are reported.
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Technological Evolution In Natural Gas Plant Automation
By N. DeyNatural Gas Liquid (NGL) Plants in Qatar have undergone major operational transformation during the last decade. The large step change in operational strategy, efficiency and maintenance optimization has occurred due to automation evolution taken place in monitoring & control , protection and asset management of all NGL Plants of Qatar Petroleum at Mesaieed. The paper will focus how such technological evolution has made flexibility in gas plant’s operation and in deriving key business decisions for operation and maintenance optimization using foundation field bus technology , integration of the plant controls to the business enterprise etc. The paper presents following three major areas of technical transformation contributed significantly towards NGL Plants upgrade indicating the problem faced , application of new technology , the challenges faced while implementation and benefits achieved in terms of operability and maintainability. The paper provides the multifold benefits achieved in above three major areas of automation transformation in various NGL Plants along with its cost benefits analysis.
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Structural Evolution Model for the North Kuwait Carbonate Fields and its Implication for Fracture Characterisation and Modelling
Authors P. Richard, L. Bazalgette, V.K. Kidambi, K. Laiq, A. Odreman, B. Al Qadeeri, R. Narhari, C. Pattnaik and K. Al AteeqiThis paper presents a new structural model for the North Kuwait Carbonate fields as well as its implications in term of fracture modelling and field development. It also describes a workflow which can be used as foundation for further fracture modelling study at production and exploration scales alike. This workflow consists of a four step approach: 1) elaboration of a regional structural model, 2) creation of 3D conceptual fracture diagrams, 3) elaboration of constraints capturing the key elements of the conceptual diagrams and 4) creation of fracture model properties for further dynamic simulation. The application of this workflow resulted in the creation of a series of fracture models for the North Kuwait Carbonates fields. During the first step of the study, a new structural model has been elaborated based on key kinematic observations from well and seismic data, as well as experimental and field analogues which have been linked to the known regional phases of deformation. These main phases of deformation are 1) post Triassic rifting, 2) Alpine 1 - late Cretaceous transtension and 3) Alpine 2 - Mid Tertiary compression related to the Zagros formation, which has the greatest impact on the formation of the pre-Gotnia structures and fracture development. The major difference between the new model and previous structural thinking is that the formation of the compressional folds in the Carbonate fields (an event that shaped the current outline of the fields) has happened during the Tertiary time instead of Jurassic time. The proposed structural evolution has been used to define characteristic structural domains. These structural domains have defined a foundation to elaborate conceptual fracture diagram to support fracture modelling study work. The fracture conceptual models have potential implications on fracture development and preferred direction of horizontal and deviated wells. Greater fracture connectivity is expected in compressional ridges developed in Tertiary time, while in the area between the compressional ridges, less dense fractures and probably more cemented fractures (likely to have developed before hydrocarbon emplacement ) are expected. The new view on the timing of the structural development (i.e., late uplift of compressional ridges regionally) also has possible implications on maturation/charge history as well as reservoir properties development. The new proposed model for structural evolution is now being used as a foundation for appraisal and fracture modelling activities of the pre-Gotnia carbonate reservoirs. A fracture characterisation study integrating all available static and dynamic data is ongoing.
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Continuous Incremental Reserves in an Oil Rim Marginal Field Development through Integrated Technical Initiatives and Technology Advancements
Authors R. Masoudi, H. Karkooti, K.S. Chan, M.B. Othman and M.M. AltunbayOil rim reservoirs are commonly marginal reserves with challenging drive-systems with high development cost and, therefore, are commercially less attractive. Development evaluation of such complex fields with the conventional methodologies and technologies may result in unsuccessful scenarios. The studied field, located in offshore Peninsula Malaysia, is a marginal oil rim reservoir with the oil column less than 42 ft with limited oil-in-place. The field was initially evaluated as a challenging development and a non-commercial asset. However, the integration of various technical initiatives and applying new interpretive techniques turned the field into an attractive asset and reserves have been continuously upgraded since the field development started. The field was undergone proactive phasing development and reservoir management with a fit-for-purpose monitoring plan. The development strategy with long horizontal wells (i.e., up to 2 km) and smart completion with inflow control devices was matured through the development phasing and well-by-well performance evaluation. Various tracer applications with the PLT campaign in the long horizontal wells pre/post water-breakthrough (WBT) were used to justify the long horizontal wells. Well placements relative to contact were progressively improved allowing the delay in WBT and increasing the RF. Production rate, draw-down and GI/GP were continuously optimized pre/post water/gas break-through. Simulation model incorporated robust modeling of flow dynamics of the oil intervals in the capillary transition zone and long horizontal wells with smart completion modeling using the segmented well approach. The applied development strategies together with the proactive reservoir management made the field development as a record successful case in Malaysia. The recovery factor progressively increased from earlier 16% to 35% presently. In this paper, suggested workflow, guidelines and key tasks with the field data and the results are presented and discussed for the studied field.
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BlowFlow - Next Generation Software for Calculating Blowout Rates
Authors H.C. Karlsen and E.P. FordA blowout is known to be the most severe event that can happen during explortation of petroleum resources. Oil-spill preparedness is important in general, particularly in the arctic region where uncertainties about consequences are high and contingency planning for major accidents requires extra attention. Calculation of blowout rates and durations from potential blowouts is an important part of environmental risk management, both in the planning phase of a well and during otherwell activities. BlowFlow is a software tool that has been developed for risk based evaluation of blowout scenarios in order to quantify blowout flow rates, volumes and durations. The results can be used as input to Environmental Risk Analysis, to dimension the emergency preparedness organization and identify both probability and consequence measures in the oil-spill preparedness planning. BlowFlow is meant as a cross-disciplinary tool for communication between petroleum, reservoir, drilling and HSE engineers. The basic design has been inspired by the guidelines given in [1]. Based on a fixed definition of potential blowout scenarios, BlowFlow provides probability distributions of potential blowout rates, durations and volumes for that can be used as input for the Environmental Risk Analysis. Since there are large uncertainties involved at the stage when such an analysis is performed, a stochastic modeling approach is used, i.e. Monte Carlo simulations and spline interpolations, based on multi-discipline expert input.
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Achieving Maintenance Excellence in Maersk Oil Qatar
More LessMaintenance Excellence for Maersk Oil Qatar is about a development and a change journey aimed at positively influencing behaviours including system and process transparency and scalability. This journey questions ways of working and current practices through review of maintenance strategies, policies, CMMS (SAP) functionality and people. In collaboration with our knowledge base, off and onshore personnel and systems, MOQ is seeking to improve why, how and when we maintain our assets, to achieve Maintenance Excellence. Maintenance Excellence is simply a framework for working more efficiently and effectively. Ensuring that we maintain 'In-service integrity' at all times by "fixing forever, instead of forever fixing". This is achieved by treating the root cause of a problem and not just the symptom. Understanding the current position and why change is required. It is essential to make a step change from Reactive to Proactive maintenance, thus achieving compliance within the framework of MOQ policies, standards and strategies. Through developing the Strategy; Populating the Plan; Scheduling Activities; Executing Work; Analysing the Data; Managing Performance - making perfection the goal, Maintenance Excellence will follow. MOQ Policy; Defines the aspirations to achieve Maintenance Excellence. Drive the development of safe systems of work and the overall assurance of integrity and reliability for plant, systems and equipment. Based on the Standard PAS55 or ISO055000; this clearly states the approach and principal methods for managing assets and asset systems. Maintenance Strategies; These are developed through a risk based approach whereby high criticality equipment and packages are subject to detailed analysis e.g. FMECA . Followed on by the Structure of how we manage work; introducing commonality across our assets connecting our people to our technology, sharing best practice and removing waste. The introduction of new Technologies also includes; the CMMS (SAP), Dashboards, (BO) and Document control (EDMS) enabling people to gauge process effectiveness and business performance. Ensuring the right people possess the correct competencies, behaviours, attitude and experience to deliver excellence in their role. Through development and communication, preparing, training and coaching our people, enabling competence and empowerment. This collaboration and adherence to the plan will deliver a seamless implementation. Through continuous assessment we will remain on track, not losing focus of the end goal; only through The 3 P’s – Patience, Perseverance and Persistence will our efforts deliver a successful journey. A journey that is continuous, achieving Maintenance excellence is a living entity, constantly evolving to the many demands made by the business, giving more flexibility in how we espouse continuous improvement. Delivering vision to why, where, when and what we maintain and at what cost. Maintenance Excellence is a lifecycle approach for Continuous Improvement.
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Seismic-Based Stochastic Porosity Prediction in a Giant Field: A Fine-Scale Quantitative Approach in Carbonates
Authors S. Samantaray, R. Moyen, J.-M. Michel, A. Bouziat, A. Yahia and N. Al ZaabiStochastic inversion of 3-D seismic data is used increasingly for reservoir characterization. It provides information on the reservoir at a much finer scale than deterministic inversion and delivers multiple scenarios for uncertainty analysis. In this work, a stochastic seismic inversion workflow has been developed to characterize porosity variations in the Thamama reservoir of the giant Field, onshore Abu Dhabi. In contrast to traditional band-limited inversion, this stochastic inversion workflow first generates high frequency models of acoustic impedance which can be used directly for geomodelling without downscaling. Next, a collocated co-kriging sequential Gaussian simulation technique has been applied to generate fine scale 3-D porosity realizations constrained by the impedance stochastic models and by log porosity data. In the example, post-stack stochastic inversion is combined with stochastic porosity modeling to characterize the uncertainty in the spatial distribution of thin, low porosity / permeability intra-Thamama layers, which adversely affect the field water flood performance. These thin layers have been mapped using seismic-constrained stochastic workflow. P10, P50 and P90 porosity realizations have been generated which represent more or less pessimistic scenarios of lateral extent of the tight zone along the flank of the field. A number of blind wells demonstrate that the seismic-based workflow provides more accurate porosity predictions than a purely well-based reservoir model. Specific technical contributions of the work include: • Demonstrate the value of seismic information for characterizing mature carbonate reservoirs • Implement field-specific stochastic workflow to characterize uncertainty in spatial extent of thin reservoir flow barriers from 3-D seismic data • Perform seismic inversion directly in fine-scale stratigraphic grid to facilitate integration with the field geomodel
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Advanced Rock Characterization by Dual-Energy CT Imaging: A Novel Method for Complex Reservoir Evaluation
Authors H. Al-Owihan, M. Al-Wadi, S. Thakur, S. Behbehani, N. Al-Jabari, M. Dernaika and S. KoronfolA quantitative model of the spatial distribution of reservoir properties is key to understanding reservoir heterogeneity. Special Core Analysis (SCAL) data is essential input for static and dynamic modeling of heterogenous reservoirs. To provide high-quality reliable data, the SCAL program should use the right samples from the core. Conventionally, integrated geological and petrophysical approaches are applied to select samples but they generally lack consistency and seldom incorporate upscaling options. This paper presents a novel methodology for core characterization and SCAL sample selection. SCAL data is used as input for spatial distribution of reservoir properties in a static reservoir model. The analysis is performed in siliciclastics and carbonate reservoirs from wells in the Bahrah Oil Field. An integrated X-ray, CT scanning, geological, and conventional core analysis approach is applied for understanding the reservoirs. We demonstrate the efficiency of dual-energy CT imaging in producing continuous whole core scans at 0.5 mm (500 micron) spacing and in deriving bulk density (BD) and effective atomic number (Zeff) logs along the core intervals. The high resolution 3D CT images improved the sedimentological descriptions of the core and the X-ray CT-derived numerical data (BD and Zeff) are used to derive porosity and mineralogy along the whole core sections. This information is then converted into lithology logs which predicted the cross-well correlation and enhanced the previously established correlation from conventional core descriptions. BD and Zeff cross plots suggested four lithotypes in the core intervals and the corresponding lithology log helped in deriving the percentage of each type: 1. Low BD (high pososity) carbonate formed around 20% of the whole cores. 2. High BD (low porosity) carbonate formed around 36% of the whole cores. 3. Low BD (high porosity) sandstone formed around 28% of the whole cores. 4. High BD (low porosity) sandstone formed around 16% of the whole cores. The data provided a unique capability for ensuring that the plugs adequately and correctly represented the lithotype variations along the core. The overall procedure helped minimize uncertainties in defining the rock types and effectively assign those rock types to the selected samples and core intervals.
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A tool to tackle the Challenges of the Treatment of the Back Produced Viscosified Water
Authors O. Rambeau, M. Jacob, M. Rondon, S .Jouenne and P. CordelierWhen the Enhanced Oil Recovery process involves a polymer injection (P, and/or SP), both surfactants and polymer are expected to be produced with production fluid, at different ratio along field life. This means changes of miscibility of fluids versus time, leading to some challenges with regard to the process and its flexibility against time. Depending on the start up of the EOR production through field life, more water treatment difficulties would have to be managed comparing to separation issues; otherwise the efficiency of both water treatment and separation could be partially lost. This paper is focusing on water treatment technologies assessment regarding inlet characteristics of produced water in presence of HPAM polymer back production. Technologies to be tested have been chosen to tackle expected thinner oil droplets in water emulsion. To answer the request of high quality of water (oil and solids contents targets) for re-injection, water technologies like filtration and centrifugation have been assessed through lab bench screening. Results are variable depending on technologies and severity of inlet conditions but they look promising. A pilot scale has been designed, a platform of tests has been built to help projects better design their process and subsidiaries optimize existing processes. This platform supplies viscosified water with degraded polymer to mimic field conditions, which is mixed with oil and solids to generate actual field produced water. This recombined back produced viscosified water feeds the open loop for the testing of various water treatment equipments. Oil droplet size is controlled on line as well as oil content. The scale of this platform allows screening of a rather large range of characteristics of back produced water in terms of oil droplet size, polymer content and viscosity, in order to qualify a suitable technology for a given range of operability.
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“Safe Execution of a World Class EGR Facility in Abu Dhabi - The Elixier Mirfa Project”
By S. Al AttasAbu Dhabi is experiencing a clear increase in the demand profile for gas needed for pressure maintenance in oil reservoirs as well as for gas cycling in condensate reservoirs. On top of the requirements from the oil and gas fields, the Emirate is also witnessing a significant increase in the natural gas demand for power. Pressure on gas fields is usually maintained through water and hydrocarbon gas injection. Habshan is one of the first sites using an alternative through the injection of 600MMSCFD of Nitrogen into the Thamama F reservoir. Nitrogen injection improves gas recovery from the reservoir with only a very limited reduction on condensate recovery as opposed to the pure Hydrocarbon gas injection case. After two years of successful operations, the paper presents the benefits achieved, the execution performance as well as quality and HSE track record. By bringing these Nitrogen production, distribution and injection facilities into the country, the project is also supporting an intensive local knowledge development of cutting edge cryogenic technologies and its uses. For this plant built in Mirfa, a staff of about 50 people has been trained to the highest technical, operational and SHEQ standards available on the market. From an HSE perspective it is worth to mention that the project execution closed without any reportable LTI (Lost Time Injuries) notwithstanding the over 15 Million man-hours cumulated until start-up.
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Microporosity: Characterization, Distribution, and Influence on Oil Recovery
Authors S.M. Fullmer, S.A. Guidry, J. Gournay, E. Bowlin, G. Ottinger, A. Al Neyadi, G. Gupta, B. Gao and E. EdwardsMicroporosity is very common in limestone reservoirs globally and is especially significant in many large Mesozoic reservoirs in the Middle East. Despite its common occurrence there is: 1) Wide variation in its definition, 2) Uncertainty around characterization, genetic controls, and distribution 3) A rudimentary understanding of its influence on reservoir performance and hydrocarbon recovery. The results of this study, based on a global survey of microporosity and specific Middle Eastern case studies, provide clarity on each of these topics. One volumetrically significant type of microporosity occurs between micron size subhedral crystals of low magnesium calcite in matrix and within grains. This micro-pore system is very homogenous in terms of pore size distribution with 90% of pores between 1 and 3 microns in diameter. Pore throat radii range between 0.1 and 1.5 microns. Porosity, permeability, and capillarity relationships reflect this homogeneity for rocks dominated by microporosity. Rocks with less than approximately 80% microporosity exhibit a marked increase in pore system heterogeneity. A pore geometry characterization approach incorporating digital image analyses of petrographic thin-sections was developed and provides a very effective means of rapidly characterizing and quantifying the total pore system, including microporosity. The lateral and stratigraphic distribution of microporosity is systematically related to the distribution of depositional facies and the regional extent of burial diagenetic processes. Factors that inhibit burial diagenesis, such as hydrocarbon charge, also have a strong influence on the nature and distribution of microporosity. Remaining oil saturation in microporous limestone, as measured from centrifuge capillary pressure and steady state (SS) core flood experiments, is negatively correlated with the percent fraction of microporosity. Due to the homogenous nature of the micro-pore system, rocks dominated by microporosity have more favorable oil recovery than rocks with mixed pore systems. In the specific cases studied here, water provides more favorable recovery than gas. These results have implications for resource assessment, field development planning and optimization of ultimate recovery in limestone reservoirs with significant microporosity.
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A New Dual Rov Assisted Well Killing System For Deep Water Blowout Recovery: Development And Testing
Authors P. Ferrara, E. De Marchi and M. PasquiniWith the Oil and Gas drilling moving to deeper and deeper waters, offshore blow-out control and recovery methods imply bigger challenges. In this scenario of technology complexity and of ever increasing focus on safety and environmental issues, with the aim to minimize operative risks, a new dual ROV assisted well killing system for deepwater blow-out recovery was developed and patented. This system extends the range of actions to be used in case of a deepwater subsea blow-out during drilling operations. The system stands as a quick-response tool devoted to assist and enhance the probabilities of success of a vertical intervention from a Dynamic Positioning Rig on a deepwater well in blow-out, when the premises for such an intervention exist or could be created. The system is designed to use two ROVs to assist the re-entry of a killing string inside the flowing well to perform the vertical intervention. The system is also equipped with acoustic sensors for a full instrumental localization of the blow-out source in case of impaired visibility. When successful, this intervention minimizes hydrocarbons losses, environmental impact, operational costs and exposure to liability claims. The system and its sub-systems have been fully designed, developed and tested. System marinization has been addressed to, involving drilling rig operators and a third party certification body to review system interfaces, handling procedures and risk assessment for a safe use on board. This paper provides a description of the proposed intervention system, along with details on the achievements and lessons learnt in the development and testing phases.
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A Review of Alternative Methods to Classify Rock-Types from Capillary Pressure Measurements
Authors B. Lalanne and M. RebelleLab capillary pressure Pc measurements are routinely performed on core plug samples. Applications of Pc curve measurements are mainly to derive some relationships between water saturation Sw and the height H above the Free-Water-Level FWL. The resulting correlations can then be cross-checked vs. the Elogs-derived Sw so as to confirm the overall consistency of the Sw model. Ultimately, the Sw - H relationship can be used as input to the 3D model. In addition, screening of Pc – Sw relationships often allows defining robust rock-types, based on observation of Pc clusters vs. the sample porosity, permeability, mineralogy and geological facies. In the case of MICP, the rock-type classification may be further enhanced by looking at the Pore-Throat-Radius PTR distributions, related to the derivative of the Pc curve. Several methods to derive Sw – Pc relationships and classify Pc clusters are possible (e.g. Leverett, Thomeer, Johnson, Cuddy, Skelt, ..) and have been documented and published in the past. In this paper, we make a synthetic review of the pros and cons associated to each Pc classification method. Eventually, we propose an innovative way to take the best of several known Pc classification methods in defining a straightforward technique to derive robust Pc clusters and equations.
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Regional In-Situ Stress Mapping: An Initiative for Exploration & Development of Deep Gas Reservoirs in Kuwait
Authors S. Perumalla, A. Al-Fares, R. Husain, R. Mulyono, N. Al Ammar, A. Al-Kandary, H. Singh, R. Al Naeimi, U. Prasad, E. Scheele and C. BartonKOC has undertaken an initiative to generate a regional in situ stress map for 23 Kuwait oil and gas fields using the data from more than 400 wells. Key objectives of this project are to integrate all available well data sources from these fields to derive the in situ stress orientation and also to create an interactive digital stress map supported by sub-surface structural geological data including formation seismic horizons, faults and well markers with the help of visualization software. In this way, the outcome of this project is available as an interactive geomechanical knowledge base which can be viewed at regional scale. The results of this project indicate that the maximum principal stress azimuth in Cretaceous formations is consistent with the regional Zagros tectonics and it is more or less uniform N45° (±10°) E direction even across major fault systems. However the sub-salt Jurassic formations exhibit high variability in stress orientation across faults as well as in the vicinity of fracture corridors. In addition to the patterns seen in stress orientation, the geomechanical models from each field exhibited that the Gotnia Salt is mechanically decoupling the highly stressed, strong, Jurassic formations from shallower, relatively lower stressed and weaker Cretaceous formations. It was also found that these stress anomalies in Jurassic formations coincide with associated fault and fracture corridors which appear to be critically stressed. Characterizing critically stressed fractures at the wellbore scale provided an understanding of possible permeable fracture sets that could contribute to gas flow. This paper discusses detailed results of the regional stress distribution patterns including innovative criteria developed to manage quality control of stress orientation data, correlation between stress anomalies and structural geological elements in Kuwait and also covers insights developed for exploration and development strategies of deep gas reservoirs in Kuwait.
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Integration of Seismic Forward Modelling, Seismic Interpretation and Core and Log Analysis, Shuaiba Build-Up Area, Al Shaheen Field, Block 5 and Block 5 Extension, Offshore Qatar
Authors A. Uldall, N. Rameil, C.M. Cund, M.I. Emang and N. BounouaThe Shuaiba reservoir of the Al Shaheen Field (Block 5 and Block 5 Extension, offshore Qatar) can be subdivided into a larger carbonate platform area located in the NE of Block 5 and an intra-platform basin (southern part of Block 5) that was filled in by a forced regressive wedge (FRW) system during the Upper Aptian regression. The FRW is characterized by clinoforms with a marly base that act as intraformational baffles or seals. Capturing these 3D geometries in detail, and specifically the exact location and nature of the platform-basin transition, is essential to developing the next generation geomodels for field development. Hence, an integrated study of core and log analysis, seismic forward modelling and seismic interpretation of a re-processed data cube was conducted. As a start, a field-wide correlation grid of available core and log data allowed for an initial coarse understanding of the depositional geometries and defined an approximate location of the platform-basin transition. As a second step, the expected depositional geometries were forward-modelled in order to better understand possible seismic responses within the bandwidth of the available 3D seismic survey. A complication is the relatively small thickness of the examined reservoir elements that are close to the limit of vertical seismic resolution. Finally, seismic interpretation picked up on this groundwork and it was possible to clearly map the platform margin, as well as the onset of the FRW in 3D. The obtained result was a detailed 3D seismic interpretation of the Shuaiba reservoir geometries, where the interpreted elements are tied with a grid of core and log interpretations. The key elements in the successful Shuaiba interpretation was early adaption of fully integrated and iterative geological and geophysical workflows where forward modelling of seismic responses was important for hypothesis testing.
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How Mastering Flow Assurance Software Can Help The Industry Take Up The Challenges Of Marginal And Remote Field Developments And Unlock Reserves?
Authors C. Candelier, F. Papot, A. Musi and D. LarreyWith most of the world’s largest and easiest-to-exploit deepwater reservoirs already under development or producing, the industry is now facing new challenges. The tie-back of new smaller fields, often with complex fluids, to existing production facilities; or the transportation of multiphase production over long distances using large pipe diameters can appear as a viable route to unlocking reserves, which are often too small to be developed economically as a stand-alone facility. If the use of subsea technologies and innovative field architectures is a step change in the industry for the development of such complex fields; operators have nevertheless to face inherent challenges. The most demanding are the flow assurance issues arising from the different operating regimes, deeper water, remote locations, harsher environment, etc. which may also be combined with more viscous fluids and/or reservoirs at low pressure and/or low temperature. Flow assurance engineers use commercially available multiphase flow software for the design of field development facilities. Optimized design recommendations are heavily reliant on the accuracy of these multiphase flow simulators, but usually extensive sensitivity studies are needed to refine the concept in order to ensure compliance with operating constraints. With increasing demand on flow assurance tools, development works are performed by the code suppliers to improve the simulation accuracy and operators have to undertake systematic internal validation tests and to apply a methodology before qualifying released versions. This paper examines the accuracy of available commercial multiphase flow simulators against field data (oil dominated and gas dominated fields are considered) and laboratory tests. A methodology is also presented to address operational considerations such as degraded mode, turndown, pigging strategy and restart management as well as to handle uncertainty of multiphase flow simulation in the case of gas field development over long distance via a large diameter pipeline.
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3D Seismic Characterization of UER Karst, Offshore Qatar
Authors V. Zampetti, X. Marquez, S. Mukund, S. Bach and M. EmangProduced water from the Al Shaheen Field is currently re-injected into the Umm Er Radhuma (UER) Formation. To model the impact of future increase of water disposal into this unit a detailed and multidisciplinary characterization of the karst system was done. In this work the spatial distribution, connectivity and geometry of the karst network in the Umm Er Radhuma Formation present in the Al Shaheen Field has been mapped in detail using horizon extractions and time slices on full-stack, spectral whitened, discontinuity, curvature and spectral decomposition seismic volumes fully integrated with drilling and regional geological data. The presence of faults and fractures associated with the interpreted karst features was also investigated and provided alternative scenarios for the distribution of subtle (sub-seismic) areas of karstification. This 3D seismic characterization of the Umm Er Radhuma karst network helped to generate a static model. The model serves as basis for the hydrodynamic modeling that will generate different scenarios for the expected increase of injection of produced water into this karstified unit. This integrated workflow has proven to be successful for the characterization of geobodies related to karstification of carbonate rocks; providing key insights for porosity and permeability distribution in similar karst reservoirs in the region.
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Multi-Scale Carbonate Reservoir Characterisation and Artificial Neural Networks Reveals Complexity in the Shuaiba Reservoir, Al Shaheen Field
Authors S. Finlay, X. Marquez, T. Solling, N. Bounoua and T. GagigiThe Shuaiba reservoir in Al Shaheen is a complex carbonate interval deposited in a platform to basin setting that has undergone significant diagenetic alteration during burial. Properly-constrained predictions of reservoir performance depend on understanding the processes that created (depositional) and altered (diagenesis) the carbonate rock, and therefore on characterizing rock properties at multiple scales. The Shuaiba reservoir in Al Shaheen has been appraised with vertical wells, and developed using extended reach horizontal wells, affording a unique opportunity for the multiscale investigation of lateral and vertical changes in the reservoir properties. This paper integrates a unique dataset of image logs (>100kms), conventional core analysis, thin sections, mercury injection capillary pressure (MICP), whole core computer tomography (micro-CT) scans, innovative 3D imaging of the pore network and mineral mapping with QEMSCAN. This integrated multi-scale work covering several orders of magnitude from μm to km has identified seven coherent petrophysical rock types (PRT’s). These PRT’s have been validated with blind tests and subsequently predicted using artificial neural network technology that enables characterization of the reservoir at well-to-well scale. Here we present the multidisciplinary workflow used to identify the seven rock types that has been used for prediction of Shuaiba reservoir properties.
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An Experimental Investigation of the oil Recovery in the Transition Zone of Carbonate Reservoirs Taking Into Account Wettability Change
More LessIt is estimated that 60% of the world’s remaining oil is held in carbonate reservoirs. Due to its moderate permeability, the transition zone can extend over a hundred meters and therefore contain a significant amount of STOIIP. The water-oil displacements behavior is not always well understood, especially when it occurs in the transition zone where capillary effects are dominant and both phases are mobile. The oil trapping and the rock wettability in this zone appear to be two key features to deal with. They must be studied as a function of parameters such as initial oil saturation, oil characteristics, rock properties etc. There is very little experimental data available in the literature that describes these features. This study focuses on relative permeability and residual oil saturations during drainage and imbibition in carbonate reservoirs. Steady-state core floods were performed with crude reservoir oil on outcrop limestone cores, some with moldic porosity, over a very large range of initial oil saturations. Cores were aged with crude oil before the imbibition process to allow wettability change at the initial oil saturations. Two main types of limestone have been studied: with unimodal or bimodal pore size distributions. The two types of limestone cores exhibit very different responses to wettability alteration for the same oil/brine system while almost identical mineralogy. We attributed these differences to the vuggy structure of the Estaillade limestones, which might promote oil-wettability. -The inspection of the water relative permeability curves show that water wettability decreases as Soi increases, i.e. as the elevation above the contact increases, for the two types of limestones. Therefore it is not correct to derive imbibition scanning Kr curves from the bounding Kr curve at high Soi, while assuming that wettability is constant. - Hysteresis is observed for both the oil and water relative permeability curves as a function of saturation - Non monotonic evolution of Sorw as a function of Soi has been observed for the limestone with bimodal pore size distribution. This behavior is ascribed to the combined effect of increasing fraction of micro porosity being filled by oil initially as well as wettability variation as Soi increases. On the other hand, Sorw increases monotonically as Soi increases, for the limestone with unimodal pore size distribution. - The comparison between the experimental relative permeability curves and the ones derived from simple hysteresis models show that neglecting the variation of wettability along the transition zone leads to erroneous values in oil saturations thus on oil recovery.
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