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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
41 - 60 of 354 results
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Well Accessibility Considerations in Well Completion Designs for Long-Reach and Deviated Offshore Wells
Authors S. Juyanty, M. Jeffry, D.M. Shivananthan and C.H. RohAA is a new gas field located offshore Sarawak currently under field development planning phase. The elongated field structure consists of multi-stack reservoirs that are located up to 15,000 ft tvdss. Two options for developing the shallow Phase 1 wells (down to AA300 reservoir) have been assessed; completing at either one or two wellhead platforms. To decide between the two options, the team needed to be confident about the ability to safely intervene these wells in the future, which triggered detailed accessibility analyses for all wells considering various intervention methods. Four main intervention methods assessed were slickline, braided line, electric line (E-line) and coiled tubing (CT). This paper provides the details of well accessibility analyses conducted during development planning stage. Sensitivities on the types of intervention activities, bottom-hole assemblies and friction factors are also studied. The findings from the study have significantly changed the well completion designs of the long reach deviated wells justifying use of smart wells. This systematic well accessibility approach was applied for the first time to replace the traditional rule of thumb of a simple 60 degree deviation used as a cut-off for well accessibility.
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Factors That Affect Gas-Condensate Relative Permeability
Authors S. Kalla, S.A. Leonardi, D.W. Berry, L.D. Poore, H. Sahoo, R.A. Kudva and E.M. BraunWhen the pressure in a gas condensate reservoir falls below the dew point, liquid condensate can accumulate in the pore space of the rock. This can reduce well deliverability and potentially affect the compositions of the produced fluids. Forecasting these effects requires relative permeability data for gas-condensate flow in the rock in the presence of immobile water saturation. In this study, relative permeability measurements have been conducted on reservoir rock at a variety of conditions. The goal has been to determine the sensitivity to interfacial tension (which varies with pressure) and fluid type (reservoir fluids, pure hydrocarbons, and water). The results show a significant sensitivity to fluid type, as well as an interfacial tension sensitivity that is similar to that reported by other researchers. For obtaining relative permeability data that is applicable to a specific reservoir, we conclude that laboratory measurements should be conducted at reservoir conditions with actual reservoir fluids. The measurements reported here used a state-of-the-art relative permeability apparatus of in-house design. The apparatus uses elevated temperature and pressure, precision pumps, and a sight glass with automated interface tracking. Closed-loop recirculation avoids the need for large quantities of reservoir fluids and ensures that the gas and liquid are in compositional equilibrium.
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Collaborative APC Project Management
By P. SinghLNG Industry is in next era of optimizing and maintaining huge LNG capacities, where QATARGAS is contributing 42 MMTPA out of QATAR’S Visionary delivery of 77 MPTA LNG. Mega trains also brings together range of complex technologies and a challenge to automate and cruise control by these technologies with emphasis on reduction in emissions, better asset utilizations, energy efficient operations and controlled product specifications. QATARGAS operates its world class facilities with state of art optimisation tools implemented on On-Shore facilities starting with Inlet reception unit, Condensate Stripper, Fractionation Units, Liquefaction Units, Acid Gas Treating Units, Scrub Column, Acid gas enrichment units and Sulphur recovery units. QATARGAS operates its 7 LNG trains with 62 such large APC controllers and overall asset wide linear plant wide optimizer to negotiate and control various constraints within different units with an objective to maximize revenue with minimum energy index operating with the defined operating /optimisation envelop of operating assets.
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Application of Statistical Analysis on Vertically Variable Azimuthal Anisotropy: Case Study from a Carbonate Field Offshore Abu Dhabi, UAE
Authors S. Nakayama and K. BelaidIn the mature oil and gas fields offshore Abu Dhabi, reservoir properties required for static and dynamic models are relatively well-defined by a number of wells. On the other hand, seismic data are considered as a fundamental and primary source to determine and optimize well placements. Azimuthal velocity analysis using wide-azimuth 3D-2C OBC seismic data is performed on different formations where several drilling issues arose mainly due to two dominant tectonic forces in the region. The results reveal different magnitude and orientation of azimuthal anisotropy from overburden to reservoir level. Available FMI and DSI logs confirm consistency between seismic and borehole-driven azimuthal anisotropy. The analysis results are also in agreement with the regional geology and tectonic history. Azimuthal anisotropy analysis generally provides two types of information such as the orientation of anisotropy and the amount of anisotropy. The amount of anisotropy can be simply quantified while the information obtained from the azimuth data has some complexity as it is a periodic function. In this respect, a statistical model of the bipolar von Mises distribution is proposed to determine the preferred orientation of azimuthal anisotropy. The model also provides the concentration parameter that can quantify the degree of preferred dimensional orientation of azimuth data. Additionally, we show utilization of the azimuthal anisotropy analysis particularly on a non-fracture layer and its benefit to field development by the analysis of spatially varying mud weight prediction.
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Selection of Power From Shore for Offshore Oil and Gas Developments
Authors E. Thibaut and B. LeforggeaisWith a step out distance of 170 km and a design power of 55MW, Martin Linge offshore gas field, will be the longest AC submarine cable power supplying an entire offshore Oil and Gas platform from the shore. This field development comprises a platform with a jack up rig and a Floating Storage Offloading unit. This paper discusses the criteria to consider and select a power from shore concept instead of an offshore Gas Turbine power plant which is the current practice in the offshore Oil and Gas industry. Since in a first approach, for such long step-out distance, the choice of power from shore would be to select a DC transmission line, the paper discusses the design and the main technical challenges of this long step-out AC transmission development. Finally, the system approach, required for the development of the onshore and offshore part of the project, is described.
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Shallow Gas Confirmation by Slow Shear Wave Using New LWD Sonic Quadrupole Technology
Authors N.T. Son, A. Pradana, M.F. Hashim, M.Z. Aznor, A. Ahmed, A. Zolhaili, C. Maeso, W.F. Kent, H. Yamamoto and S. BramantaA re-development drilling campaign was planned for a brownfield in South East Asia. In previous campaigns, conducted between 10 and 20 years ago, limited data had been acquired in the shallow to intermediate sections. At the time extensive wellbore stability issues led to stuck pipe events and lost wireline strings. The absence of data from the shallow sections resulted in difficulties for seismic ties and identifying potential shallow hazards. The planned development phase involved long 12 ¼ in hole sections from a very shallow depth, with extensive borehole builds from vertical to 68°. In order to acquire shallow hole information, log data requirements led to a long bottom hole drilling assembly including multipole sonic measurements. The sonic measurements were acquired using a new multipole sonic tool in an 8 inch collar. Real time quality control using transmitted coherence peaks and pumps off stations gave confidence in the real time compressional data. Post processing of the full recorded mode waveforms confirmed the real time values. For shallower intervals Leaky-P dispersive processing allowed determination of formation compressional signals (differentiating formation and mud where they are close in value). Formation shear values were always slower than the mud and so were not available from the Monopole signal. The Quadrupole mode contained slow shear through the majority of the section. Shear data was seen in the range of 275 – 920 usec/ft. The compressional and shear data is the shallowest borehole sonic data acquired in the field to date. Presence of shallow permeable gas was confirmed by good quality shear sonic data in a highly unconsolidated formation. The sonic data was also used for seismic inversion. Historically acquisition of shallow interval sonic data has been problematic in South East Asia due to soft formations and wellbore stability issues. This paper demonstrates the use of LWD mulitpole sonic to address this challenge to reduce drilling risk and geological uncertainty.
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Qatargas Flare Reduction Program
Authors I. Bawazir, M. Raja and I. AbdelmohsenQatargas produces 42 Million Tonnes Per Annum (MTA) of Liquefied Natural Gas (LNG). The Qatargas facilities comprise seven LNG Trains, including four of the world’s largest mega-trains, which were commissioned between 2009 and 2011. Routine baseline flaring is encountered during normal LNG plant operations due to the essential requirement to maintain purge gas flow within the flare system to prevent air ingress and consequent explosion hazards. During unplanned facility trips, restarts or planned facility shutdowns, process gas is also flared per operational requirements. Qatargas has made significant progress in reducing flaring from its LNG trains in line with the increased national focus on flare minimization and the Company’s desire to reduce its emissions and carbon footprint. This has been made possible through operational initiatives on source reduction, increased plant reliability, reduced shutdown/start-up flaring and a sustained focus on flare minimization facilitated by multi-disciplinary Flare Management Teams (FMTs). Enhanced acid gas recovery and operational excellence initiatives on source reduction and plant reliability at Qatargas’ older, conventional LNG trains have successfully reduced flaring by more than 70% between 2004 and 2011. A comprehensive project is currently underway at the LNG mega-trains to reduce current baseline purge flaring by approximately 70%. Qatargas is also undertaking a long-term capital project to install interconnections between LNG mega-trains to re-route gas encountered during process events rather than flaring. Additionally, Qatargas’ pioneering Jetty Boil-off Gas Recovery (JBOG) Project, which will commence operation in 2014, is expected to reduce LNG loading flaring by over 90% and recover approximately 600,000 tonnes per year of flared gas. This paper provides an overview of Qatargas’ flare management approach, the Company’s main drivers and challenges for flare reduction and the various initiatives currently underway to manage and minimize flaring. These include the major capital projects noted above as well as enhanced awareness, monitoring and reporting, and operational source reduction successes.
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Sweet Spots Identification in a BCG Play in Sichuan Basin China
Authors Z. Jinying, G. Biwen, L. Xi, D. Mueller, S. Antipenko and A. RolphUnconventional resources are considered to be a game changer for near-term and future energy, the huge resources of unconventional gas worldwide will be critical to the world economy. The JinQiu (JQ) block, joint operated by Shell and PetroChina, is located in the northwest of the Sichuan basin, with target reservoir in upper Triassic Xujahe formation (from T3x1 to T3x6). The play concept for the JQ block is a basin centered gas (BCG) play which consists of overpressured, stacked alluvial feldspathic litharenite reservoirs with a very high net-to-gross (N/G) and low porosity and permeabilityties in T3x2 and T3x4 members, and low N/G, low porosity and permeability calcarenites interbedded with calcareous coaly shales in T3x3 and T3x5 members. Major challenges that the operators face to produce these unconventional resources are identifying subsurface sweet spots and utilizing techniques such as wellbore stimulation to generate commercial projects. The process of sweet spot identification in the JQ block includes the following steps: 1) confirming and updating the play concepts from wells early in the play appraisal phase; 2) determining key geological, geophysical and petrophysical elements for the positive well results to define subsurface critical risks factors such as play concept model, reservoir properties, resource density, predicted facies distribution (i.e. channel orientation and distribution) and fracture geometries etc, and 3) follow play based exploration workflow by overlaying critical risk maps for each element to define areas of common risks segments (CRS). Using the results from these CRS maps and knowledge obtained from the positive well results enable us to identify sweet spots for future exploration, appraisal and development drilling. After this study was completed, one additional appraisal well used as a blind test was drilled and finally got an encouraging well testing result. Conclusions from this study are that, for unconventional plays, such as this BCG play, sweet spotting is important to define developable hydrocarbon resources, where all subsurface disciplines (geology, geophysics, petrophysics, reservoir engineering, completions and drilling) should be integrated to drive the decision making. In addition, the configuration relationship of fractures geometries, predicted facies distribution and resource density plays a critical role in the sweet spotting for BCG play exploration, appraisal and development.
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Study of Damage Evaluation of Hydraulic Fracturing to Reservoirs
More LessClassic hydraulic fracturing analysis is based on tensile strength of rock, failure criteria of fracture mechanics or Mohr-Coulomb criteria. The existing hydraulic fracturing theories consider little of permeability of fracture reservoir and effective fracturing range, which is exactly the purpose of fracturing. On the other hand, when evaluating effect of massive hydraulic fracturing (MHF), there may be lots of fracture initiation points and cracks due to large range of MHF, which brings huge challenges to numerical calculation of hydraulic fracturing. MHF will have an effect on a large range of reservoir and accompany in-line micro-earthquakes, which indicate that lots of hydraulic fractures of different scales and directions are generated. Therefore, there will be difficulties to analyze cracking and propagating and estimate geometrical parameters by tensile criteria or fracture criteria. Even if the classic method is feasible, processing of element grid after rock failures will be a problem. Aguilera (1995) considered shear failure criteria as failure criteria of rocks and proposes fracturing theory of divergent or branched cracks, and that explains the generation of in-line micro-earthquakes in hydraulic fracturing. But the present analysis is just a qualitative method but not quantitative method. In fact, the basic goal of hydraulic fracturing is enhancing permeability of reservoirs as large as possible rather than producing one or two fractures. Analysis of fracturing effects is analyzing the influence of effective fracturing range on reservoir permeability. While the existing hydraulic fracturing theories just consider propagations and fracture initiations of one or two cracks but little of the quantitative estimation for effective fracturing range. Hence it is necessary to find a better mechanical method to make up deficiencies of the existing fracturing analysis and overcome the difficulties of processing element grid after rock failures. This study introduces continuum damage mechanics (Gurson damage model) to hydraulic fracturing, analyzes theories and techniques of hydraulic fracturing of porous reservoirs in terms of continuum damage mechanics and discusses damage effects of hydraulic fracturing to reservoirs. An analysis evaluation system of hydraulic fracturing continuum mechanics is set up, and by using damage theories, a method of analyzing hydraulic fracturing in fissured porous reservoirs is discussed.
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Underbalanced Drilling Technology for Unconventional Tight Gas Reservoirs
Authors H. Qutob, K. Kartobi and A. KhlaifatThe increased demand for more sources of clean energy such as natural gas from unconventional reservoirs has forced the industry to explore the more challenging tight gas reservoirs. Tight gas reservoirs constitute a significant proportion of the world’s natural gas resource and offer great potential for future reserve growth and production. However, to meet future global energy demand, access to tight gas reservoirs requires innovative and cost effective technical solutions. Yet, tight gas reservoirs are often characterized by complex geological and petrophysical systems as well as heterogeneities at all scales. Exploring and developing tight gas accumulations are both technically and commercially challenging due to the large subsurface uncertainty and low expected ultimate recovery per well. Appraisal of deep tight gas reservoirs offers many challenges, including production rate predictions when wells are drilled overbalanced. Overbalance leads to near wellbore damage to the rock matrix and fractures. Damage to natural fractures intersecting the well can prevent their detection leading to missed productive intervals. In addition, the operating environment is very challenging and that affects the decisions for data acquisition. The use of saltsaturated mud systems creates a contrast and uncertainty in the data. Hence, the quality of data acquired is compromised. In the 80’s hydraulic fracturing of deviated wells was the method of choice for developing tight gas reservoirs worldwide. Although sound in principle, in practice problems were experienced and caused either by poor cleanup due to fluid incompatibility, erosion of surface facilities or early water breakthrough due to fracturing into the water leg. In the 90’s horizontal drilling became common practice as new drilling technologies developed and proved to be very successful in many tight gas fields. However, conventional drilling operations introduced foreign fluids and solids into the reservoir which lead to several different formations damage mechanisms that prevented the identification of the gas production potential from these wells. In the late 90’s underbalanced drilling (UBD) was introduced, mainly to avoid the frequent drilling problems associated with total losses into these tight gas reservoirs. However, significant productivity gains were also observed and this became a key driver to apply the same UBD technology in tight gas fields. This paper provides a technical overview of the state-of-the-art UBD technology used to develop unconventional tight gas reservoirs. Two real case histories from eastern Jordan and South West Algeria will be presented and discussed.
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Permeability Multiplier Prediction using 3D OBC Seismic Data
Authors T.M. Matarid, K. Ibrahim and M.S. IbrahemThis work describes an approach in characterizing fractured reservoir of upper Jurassic Carbonate using seismic azimuthal anisotropy. The ultimate objective of this study was to attempt to map permeability multiplier inter-well for the contribution to the simulation model and the subsequent development plan of an oil field offshore Abu Dhabi. The azimuthal seismic anisotropy for fracture prediction method showed fractures that are similar to those indicated by well methods and therefore seismic can be used to detect natural fractures between wells. The confidence in the seismic fracture prediction method’s ability to capture information about fracture in Carbonate reservoir has increased if the well data are accurately integrated. The study interval exists in the dense zone of the Upper Jurassic reservoir with total thickness of 120’. The fractures evidence have been compiled from well data, such as Core, FMI, orthogonal shear sonic, production test, multi-arm caliber….etc. Present day stress is captured from induced fractures direction, borehole breakout, offset field stress map, Eocene structure map and world stress map. All compiled information’s indicated maximum horizontal stress of N10°-30°E direction. The four sectored wide azimuth seismic data set have been fitted to an ellipse to find out the fast and slow velocity direction and the difference between those velocities. The Interval Velocity is sensitive to Lithology, porosity, pore fill; the Vint-Slow is sensitive to the minimum horizontal stress. The lower the VINTslow, the less the minimum horizontal stress, which allows the fracture apertures to be more open. It is observed that the seismic anisotropy map for fractures showed a dominated direction (NNE-SSW) that match with present day stress field. The azimuthal Vint records current day stress field, not paleo-stress field. Good correlation between well permeability multiplier and the fractures map, particularly at the two reference wells. Following the analysis of the azimuthal seismic anisotropy maps such as azimuthal amplitude and interval velocity, a good correlation has been observed between the seismic anisotropy components and the production well test. The two seismic anisotropy components that showed a great deal of link with the computed well permeability multiplier are the computed slow interval velocity and the anisotropy azimuth deviation from the known present day stress. Therefore, the following equation has been written to invert those azimuthal seismic components into permeability multiplier. The resulted map showed match at both input wells and one blind well. Perm. Mult. = ( X * Vint Fast-Slow ) + ( Y / Vint Slow ) + COS (Ref. AZ – Seis. AZ)
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Integration Of Seismic Variance Attribute With Stochastic Error Surfaces To Have A Better Definition Of Structural Uncertainty - A Case Study
Authors D. Ghosh, B. Al-Enezi and D. Al-MatarStructural uncertainty is defined by creating stochastic error surfaces built on control points. Uncertainty is zero at the drilled locations and varies smoothly away from the wells. The other factor that enhances uncertainty is fault-zone. This study aimed at generating a composite model integrating these two determinants of structural uncertainty. The study is done on Mauddud surface in part of the Greater Burgan Field, Kuwait. The seismic guided surface was created incorporating tops of 13 drilled wells. Sequential Gaussian Simulation was used to generate stochastic error surfaces having normal distribution using these 13 zero value control points as input. Deviation of the actual Mauddud top from the given seismic surface was calculated to be to the tune of ±60’. The stochastic error surfaces were multiplied with a constant so that the surfaces closely represent the perceived uncertainty captured in these drilled wells. Seismic variance attribute was used to capture the uncertainty in fault zone. Variance was extracted on Mauddud surface from the variance cube generated. This variance surface was normalized with minimum and maximum values 1 and 6 respectively to use it as a multiplier to the stochastic error surfaces. The assumption was that the uncertainty will increase six times where there is maximum variance. The stochastic error surfaces were multiplied by the normalized variance surface to get the composite uncertainty. This uncertainty model was used to predict the uncertainty of Mauddud top in some wells drilled subsequently. The actual tops were found to be within the P10-P90 range except for a graben well where it was beyond the range. This study thus provided a model to quantify the range of uncertainty in predicting tops taking into account both distance from control points and uncertainty associated with fault zones as captured by seismic variance.
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Investigating the Dynamic Three-Dimensional Loading Effects on Perforating Guns Imposed by Shaped Charges
Authors G.G. Craddock, W. Zhang, J. Wight, J. Rodgers, T.S. Glenn, M. Serra and T. BettenmannModern developments in shaped charge technology have resulted in greater explosive loads being used on perforating guns, which has stretched the capacity of perforating guns into uncharted territory. Traditional gun design approaches and standards use collapse pressure calculation and swell measurement with overloaded charges as design verification methods. The extremely complicated interactions between explosives, fragmented casings, and the gun wall are evaluated on an empirical basis, and the nature of these interactions is not well understood. In this paper, a new design model is presented that augments traditional design approaches and provides gun designers with better data on gun system structural performance, including the effects of phasing, shot density, and charge type. The loads imposed on the gun body by the explosives are multidimensional because of the spiral arrangement of most shaped charges. The resulting dynamic response of the gun body is therefore quite complex and requires three-dimensional (3D) analysis. High-frequency bending, torsion, and tensile loads are expected. The casings are typically fragmented, and some of the larger fragments can impose high impact loads on the gun wall. A fully coupled computer model has been developed that incorporates the rapid explosion, casing fragmentation, and multidimensional structural responses. Multiple instrumented surface tests were performed to validate the dynamic 3D model. Proprietary testing techniques were used to extract gun internal pressure history and gun stress history at multiple locations immediately following detonation. Redundant strain gauges were used, and shots were repeated to ensure the integrity of the data. This paper presents the instrumented gun test setup and results, along with the newly developed 3D simulation model and shock hydro model results. This paper also presents validation of the newly developed 3D model through comparisons with test data.
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Revisiting Reaction Kinetics and Wormholing Phenomena During Carbonate Acidising
Authors X.W. Qiu, W. Zhao, S.J. Dyer, A. Al Dossary, S. Khan and A.S. SultanWormholing during matrix acidizing of carbonate reservoirs is known to be predominantly mass transfer limited. Mass transfer coefficient, controlled by (1) the fluid injection rate and (2) the acid diffusion coefficient, dictates the speed and profile of the wormholes. Injection rate is easily obtained from the job execution, whereas the diffusion coefficient is intrinsically a hidden parameter of the fluid and reaction conditions. Acid diffusion coefficient data used in modeling the wormholing processes are commonly obtained at 1000 psi system pressure, which is too low to represent realistic reservoir conditions. In order to properly quantify the acid penetration inside the formation, the diffusion coefficient of acid acquired from high-pressure reservoir conditions should be used. In this study, we investigate the effects of diffusion coefficients of HCl acid as it reacts with calcite. We use a rotating disk apparatus to obtaine the CO2-impacted kinetics at downhole conditions. The test results show that the diffusion coefficient of the HCl acid is much lower at high pressure than low pressure at the same concentration due to the impact of CO2 produced by the HCl-carbonate reaction. At higher pressure, more CO2 tends to stay in an aqueous phase, which slows down the reaction of HCl and the carbonate formation. For example, at 150 °F, the diffusion coefficient of 15% HCl at 3,000 psi reduced 50% of its original value when at 1,000 psi of 15% HCl. This new set of kinetics data is then implemented in a 3D wormholing model to predict wormhole morphology and penetration velocity. The model uses a CT-scan rendered porosity field to capture the finer details of the rock fabric. Simulation results of fluid flow coupled with reaction provide new insights on how acidizing design models should be improved to more accurately quantify wormhole penetration, which then leads to more accurate production forecasts.
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An Evaluation of Digital Rock Physics Technology for the Prediction of Relative Permeability and Capillary Pressure for a Middle Eastern Carbonate Reservoir
Authors K. Guice, L. Lun, B. Gao, R. Gupta, G. Gupta, J. G. Kralik, R. Glotzbach, E. Kinney, G. Leitzel, J. Rainey, R. Kudva and M.O. Al JawhariDigital rock physics (DRP) has received considerable attention in recent years as an alternative to laboratory measurement, especially for the prediction of reservoir properties for which the right laboratory measurements are difficult to perform or require long measurement times such as the special core analysis (SCAL) properties relative permeability and capillary pressure. While measurement of these reservoir properties can certainly be challenging to execute, there is a long history of successful, high-quality laboratory SCAL measurements. Before adoption of a DRP approach to generate reservoir properties that have significant impact on expected reservoir performance, it is important that the uncertainties introduced by use of DRP are better understood. To this end, we have utilized samples from a large Middle Eastern carbonate reservoir to benchmark vendor DRP predictions of water-oil imbibition relative permeability and capillary pressure against high-quality SCAL results that were measured using consistent laboratory methods. Considerable scatter are observed in the DRP predictions that do not exist in the measured SCAL data and cannot clearly be attributed to sample heterogeneity. Wettability, which is an important input into digital rock predictions but is especially challenging to quantify in the laboratory, is shown to have a significant impact on DRP predictions of relative permeability and capillary pressure. Nevertheless, the dependence of the DRP results on wettability is inconsistent with the SCAL data. Given the additional scatter and inherent uncertainties associated with use of the DRP approach, we find that a high-quality laboratory program employing consistent test methods remains the best approach to obtain SCAL data to support reservoir definition development, and depletion objectives.
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Economics of Power Production from Forward Osmosis
Authors M. Jacob, O.F. Garnier and G. LebasForward osmosis (FO) uses an osmostic pressure gradient to induce a net flow of water from the solution feed (low salt concentration solution) into the draw solution (higher salt concentration solution) through a semi-permeable membrane. The osmotic pressure can then be converted into a hydraulic pressure used to run a Pelton turbine and to produce green electricity. The permeate flow is then always kept at high pressure (15-30 bars) to feed the turbine using a pressure exchanger; this technology is called Pressure Retarded Osmosis (PRO). Oil terminals are rejecting to sea large quantities of salty produced water (above 100 g/l) and there is a potential for the application of PRO using this produced water as the draw solution and the sea water, river or lagoon water as the low-salt feed solution. Forward osmosis between sea water and production water could be used to produce electricity with low additional environmental impact. A technico-economical study was launched to evaluate the potential interest of PRO technology to produce electricity on the Djeno oil terminal site situated in Congo. The calculated technical cost of electricity is from 350 to 650 euros/Mwhr, which is not competitive with other green energies. This high cost is mainly due to required bulk equipments and their related electrical consumption, the membrane cost being only 10% of the technical cost. So though the technology seems promising, a technical breakthrough on membrane permeability and mechanical resistance is needed to promote PRO as a competitive clean energy.
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A Novel Technique to Utilise Surface Data for Pressure Transient Analyses in Gas Producers
Authors H. Al-Kharaz, M.Z. Farooqui, A.M. Ansari and and Kapil ThakurPetroleum engineers rely on periodic acquisition of bottom-hole data to monitor changes in well and reservoir inflow characteristics, and to quantify well and reservoir parameters using Pressure Transient Analysis (PTA). However, the acquisition of this data, especially in an offshore high pressure and sour gas environment, presents many logistical challenges and operational risks, and can negatively affect expenditure and downtime performance. On the other hand, surface data is routinely available, sometimes with sufficient frequency and precision to carry out PTA. Surface data is affected by wellbore transients that must be taken into consideration for converting the surface data to bottom hole conditions with the accuracy required for proper analysis. This paper describes a novel technique to properly account for wellbore transient effects and convert surface data to downhole conditions to enable conventional PTA without the need for well intervention. The technique combines the transient wellbore modelling with a novel approach of defining coefficients in a modified bottom hole pressure equation which is described in the paper. Coefficients are calibrated using concurrent surface and downhole data sets and then utilised to convert future surface data to downhole conditions. The paper describes the findings and conclusions from a five-well pilot, which involved wells with a range of reservoir characteristics, single and multi-layer production, and with/without cross-flow. The pilot work compared PTA results utilising this technique and surface data with results generated using downhole data.
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Qatar Petroleum Experience in Implementing the Measurement Strategies for Custody Transfer, Allocation and Royalties
By C. BolivarFrom the reservoir to the final consumer sales point, the flow and quality related to energy is estimated, quantified, or in an ideal situation is measured with very low uncertainty. Organization of Petroleum Exporting Countries (OPEC) reference basket averaged $107.52/b in August, and the world oil demand growth was revised in 2013 by 25 tb/d (1), in the longer term, prices may reach $155/b by 2035 (2), additionally, energy consumption has been estimated to increase 54% from 2010 to 2035, fossil fuel will account with 82% (2). Considering these short and long term estimations, the proper management of the uncertainty levels related to measurement systems in the energy sector has an intrinsic financial risk exposure that has to be addressed, and in most of the cases, a clear framework has to be established and led by the reserves owners. Technology has been evolving to manage better levels of uncertainty, but it is an endless journey trying to find the “true value” in order to safeguard the net profits of the shareholders. In the case of National Oil Companies (NOC), this challenge is translated in major strategic paths that are fully linked to the long term vision of an entire nation, and if we consider the nations where the Gross Domestic Product (GDP) is propelled by the Oil and Gas sector, the discrepancies related to product measurement may create a tremendous impact in the domestic economy. In consequence, around the supply chain, where different parties are directly involved in energy custody transfer process, the transparency and clear measurement terms are required for the buying and sales transactions. In many of those cases, royalties payment is involved, this issue must be fully monitored and controlled by the NOCs, but clear terms has to be agreed with the International Oil Companies (IOCs) in order avoid financial losses due to sub-optimal measurement practices. Qatar Petroleum (QP) has embarked in an ambitious task to implement a “Measurement Strategy”, to be applied to all the Joint Ventures and Production Sharing Agreements Operators that are located in the State of Qatar (SoQ). One of the key elements in the Measurement Strategy is the creation of a common framework to operate the measurement systems in the SoQ. The complexity lies to boost this initiative in an environment where different players have already an intrinsic risk related to their own operations in terms of hydrocarbon imbalances due to measurement uncertainties, and every single operator could operates the measurement system with a different asset management strategy. This paper will present the case and the lessons learned from this implementation process in order to deploy an unique framework to manage the measurement systems, where, the approach utilized to manage the diversity from the managerial perspective was based in the Kotter method.
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A Study into Tubing Shear Stresses in High Rate Wet Gas Producers
Authors M.Z. Farooqui, L.B. Morshidi, M.S. Kersey, M.A. Bugti, A. Troshko and N.S. BerchaneThis paper discusses an approach used to assess liquid film erosion/corrosion effects in the tubing strings of sour, high-rate, wet gas producers. This was done as an alternative to API RP 14E, which utilises an empirical erosional velocity factor “C” to estimate maximum velocity limits to minimise the potential for tubing metal loss from erosional effects. Many RasGas wells are completed with a full L-80 carbon steel or a combination L-80/Corrosion Resistant Alloy (CRA) production string. Once on production, a thin iron sulfide scale develops on the tubing wall significantly retarding the rate of metal loss due to internal corrosion. However, shear stresses generated from the condensate/water film flowing along the tubing wall could potentially remove this protective iron sulfide coating and expose fresh metal to much higher corrosion rates. This paper describes the approach adopted to assess the magnitude of shear stress created across a range of flow conditions including well production rates, fluid properties, and completion sizes using transient 1D flow simulation and more detailed 3D computational fluid dynamics modelling. The results will be used to design future laboratory experiments to assess the effect of these stresses on the integrity and effectiveness of the iron sulfide scale in reducing corrosion rates.
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A Holistic Approach to the Development Stage of Shale Gas Resources
Authors M. Navarette, L. Chorn and M. MaucecSource rock reservoirs (SRRs) are found in conventional oil and gas basins. The development of a SRR depends on the geological, geochemistry, petrophysical, and geomechanical parameters, as well as economic constraints in the targeted area. While SRR exploration and appraisal methodologies are fundamentally different from conventional assets, the development stage takes on more similarities to conventionals. However, conceptual differences remain that require technical professionals and managers to alter time-tested approaches. Unconventional SRRs impose significant engineering constraints because reserves are spread across large compartmentalized stacked or layered reservoirs, which are highly heterogeneous and contain wide ranges of mineralogy. This paper is a continuation of the exposition on a holistic approach to shale gas and oil development, which has been developed in detail and encompasses more than 25 years of service company experience in US gas shale plays (Navarette et al. 2013a, 2013b). The objective of this work is to provide a guideline for acquiring and applying a better understanding and application of SRR reservoir quality and deliverability insights. The goal is to position geoscientists and engineers to maximize well productivity, improve hydraulic fracturing stimulation effectiveness, and optimize drilling and completion efficiency. This paper identifies critical paths and key technical elements or tasks associated with SRR field development. Previous data (seismic, logs, cuttings, mud logs, extended production tests, and optimized well construction and stimulation practices) acquired in the Screening and Appraisal stages are used. A methodical approach is presented that addresses the following key tasks: 1. Categorize critical SRR attributes and key learnings. 2. Confirm hypotheses tested in the Appraisal stages. 3. Establish drilling program plans for the best reservoir targets (sweet spots) with well location and lateral orientation. 4. Maximize the stimulation potential and recovery factor. This work provides a proven road map for the evaluation and development of SRRs. Critical paths with the associated key technical elements address and provide a project scope of challenges, which enables a holistic solution to successful unconventional SRR development.
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