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IPTC 2013: International Petroleum Technology Conference
- Conference date: 26 Mar 2013 - 28 Mar 2013
- Location: Beijing, China
- Published: 26 March 2013
501 - 520 of 581 results
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HPHT Well Basis of Design Case Study: Offshore Thailand Advanced Tubular Analyses Experience
Authors Habil Akram Rosland, E. Effendhy and S.J. ParkIn 2011, a major exploration and production oil company drilled and tested an HPHT well, the Tong Rang 3. This well is located in Bongkot field, Gulf of Thailand, about 722 km from Bangkok. This paper highlights the outcome of a post-drilling review using the Tong Rang 3 as a case study with respect to the well-design models and steps that the company will be taking towards optimizing its higher degree of HPHT development wells, which include future challenging prospects in the Gulf of Thailand. Aside from stress and pressure profiles, a good understanding of the temperature regime and heat transfer in HPHT wellbores is an important aspect of the planning process. The logs and actual well-testing operations in the Tong Rang 3 confirmed that the hydrocarbon produced contains gas condensate with 31.5% CO2. The maximum circulating temperature was diagnosed to be around 207°C while drilling to TD with a mud-cooling system in place and bottomhole temperature in excess of 227°C during well testing and a tubing-head temperature of 60°C. To improve the quality of the well design and planning process, the company has realized the importance of a case study to establish a guideline in their well-integrity process, thereby allowing the drilling team to plan similar wells using proper engineering assumptions, including basis of design refinement, based on the company’s well engineering policies. The study will not only enable aiding the wellbore and completion optimization, but can be used to improve decision making throughout the field-development campaign, thus avoiding possible underdesign and achieving long-term well integrity and cost optimization. This paper will detail aspects of the well design incorporated in the Tong Rang 3 and provide a discussion and comparison between the plans vs. the actual design throughout the execution of this HPHT well, focusing on advanced tubular design from a temperature simulations aspect. It will also highlight the effect of tubular heat-up through comprehensive sensitivity analyses, while understanding how the currently available technology can be used to support an integrated basis of design model to successfully establish a representative HPHT wellbore configuration, subsequently signifying relevant well-construction parameters to ensure an effective and safe design for future HPHT wells.
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Reaction Transport Modelling (RTM) Application to Predict the Dolomitization Distribution in Carbonate Hydrocarbon Reservoirs
More LessThe application of Reaction Transport Modelling to cases of dolomitization allows testing the genetic interpretation and may help in predicting the lateral extension of the dolomite hydrocarbon reservoir in the subsurface. The results of numerical diagenetic modelling simulations of four different dolomitization processes are presented. In all the cases the simulations suggest that the hydrogeologic system is the most important driver for dolomitization: in fact the final geometry of dolomite bodies is greatly affected by the permeability field and presence of fractured zones.
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Continental Carbonates as Hydrocarbon Reservoir, an Analogue Case Study from the Travertine of Saturnia, Italy
Authors Paola Ronchi, Cruciani Francesco and Cirilli SimonettaThe Pleistocene Saturnia travertine represents an analogue of the pre-salt continental carbonate reservoir discovered on both sides of the South Atlantic margin. Two sub-horizontal travertine plates, few tens of metres thick and extended over an area of several kmsq, have been studied in 3D quarries exposures. The aim of this study was to reconstruct the facies variations and associate petrophysical properties applying an integrated multidisciplinary approach. The Saturnia travertine complex, due to warm waters spring still active in the area, is made of various stacked banks, separated by emersion erosive phases, showing alternation of lacustrine tabular bodies, terraces and sills. The facies association includes crystalline crust, pisoid, paper-thin raft, coated bubble, reed, lithoclast-breccia, micritic travertine. The δ13C, ranging between +4‰ e +8‰, supports the CO2 volcanic mantel source, while the δ18O from -5‰ and -9‰ is in agreement with warm meteoric water as for other travertine in the area. The Sr ratio isotopic signature is agreement with the carbonate derived from dissolution of Mesozoic deep seated carbonate. The facies reservoir properties have been studied through an integrated approach that includes porosity and permeability analysis on plugs, 3D X-Ray Computer Tomography, which evidenced the porosity connectivity, and image analysis on micro scale under thin section (microporosity) and macroscale on large rock slabs to define various porosity indexes (shape, roundness, pore size). A strong heterogeneity of the pore system and variable connectivity were pointed out. The porosity ranges from 4 to 30% and permeability is highly variable reaching hundreds of mD. The average pore diameter is between 1 and 4 mm, microporosity is low and the prevailing pore type is the inter-granular one. The study highlighted also that in travertine, the investigation should be conducted at a large scale in order to measure the large pores and wide scale connectivity.
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A Coil Shooting Survey in the Angola Deep Offshore
Authors E. Zamboni, N. Khaled, A. Kusuma, J. Guerra, P. Capelle, S. Tchikanha and D. LarraganaThe Calulu PDA (Pre-Development Area) is located in the Angolan deep offshore. The water depth ranges from 1500m to 2500m. The area is characterized by a very complex geological settings caused by the presence of extended salt canopies. The main reservoir levels are turbiditic sands located in highly structured sub-salt areas. The area was covered in 1999 by a conventional Narrow Azimuth Towed Streamers (NATS) 3D seismic survey. As most acquisitions of that period, the data suffer of an intrinsic limitation: the maximum recorded offset is about 3.5 km. Despite recent reprocessing efforts with the latest state of the art techniques (3D SRME and RTM) the final data quality was still not sufficient to correctly image the complex salt tectonics structures and the steeply dipping anticlinal flanks. For this reasons, in 2011, TEPA and Partners decided to acquire a long offset (more than 7 km) NATS seismic survey over the area (~1300 Sq.km) complemented by a coil shooting survey over a sub-area of interest (~700 Sq.km). The required turnaround deadlines for the whole project (Fast Track and Final Processing) was a real challenge for all the parties involved (TOTAL and WesternGeco): a raw TTI (tilted transverse isotropic) RTM PSDM was available within 4 and 5 months respectively after the last shot point for the NATS and Coil. As a seamless workflow, the full processing took then the pace to deliver the final results within 12 months after the last SP. Scope of the final processing was to refine the existing TTI velocity model and produce improved images, with respect to the Fast Track, of the Coil data set using various migration algorithms (Beam, Kirchhoff and RTM). The most representative results among the different techniques from both surveys are presented and compared in this paper.
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Field Experience with First Twin-Screw Multiphase Pump in a Saudi Arabia Oil Field
More Lessuld be carefully approached and evaluated on a case by case basis. MPP may not be the best alternative for all weak wells. For example, a dead well, which cannot flow smoothly to the surface, does not provide sufficient wellhead pressure to the MPP inlet, and therefore is not a candidate for MPP. The MPP (twin-screw technology) has been installed in a remote field to boost the oil production from three oil wells with high water cut and insufficient pressure to flow to the processing facility. For these wells, a MPP package was designed and installed at the field manifold. The unit was a simplified portable pumping system powered by a diesel generator. The MPP is now operated unmanned with local controlling and monitoring systems. The trial test has proven the high percentage of operating efficiency of this type of MPP1. An oil gain was realized from the manifold using this MPP, which improves the oil recovery and sweep in the subjected area. The MPP has proven its reliability to introduce a successful performance for specially selected low flowing wellhead pressure (LFWHP) wells’ applications. In addition, the MPP has further advantages in terms of piping modification requirements, maintenance ease, power consumption, compatibility with intelligent fields, monitoring operations, etc. This paper discusses the advantages of utilizing MPP with twin-screw technology in a Saudi Aramco field. The paper also addresses project implementation as well as the operating experience with the MPP.
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What Matters to Flow: West Africa Field Case History
Authors Brodie Thomson, Anna Apanel, Robert Tester, Gaspar Marques and Ginga MateusThe subject field, located in deep-water Angola Block 15, was discovered in 1999, achieved first production in 2003 and was abandoned in 2011. Over its 7-year life, the field reached a peak production of 90 thousand BOPD and produced nearly 100 million barrels of oil from a high-quality stacked Lower Miocene deep-water channel complex. This field provides a unique opportunity to perform a look back on how well the reservoir characterization, reservoir modeling and reservoir performance predictions made at project funding matched with the final actual field performance. The West Africa field was a subsea development tied back to a FPSO (Floating Production Storage Offtake vessel). The original depletion plan called for crestal gas storage and peripheral water flood. The field was ultimately developed with a combination water flood / downdip gas injection process. The factors that drove the evolution in the depletion plan are reviewed. Despite the significant changes to the depletion plan, the funding models did a good job of predicting average reservoir behavior such as most-likely recovery and production plateau. However, both gas and water breakthrough and build up was faster than expected. These factors were offset by higher well productivity and larger in place oil volumes. The reasons for the models not matching actual performance are discussed. 4D seismic acquired after 3 years of production was particularly effective in illuminating gas and water flow pathways in the reservoir that had not been modeled or predicted. Water injection was not initiated until about three months after first production. Initial field performance under pressure depletion drive provided valuable reservoir characterization data. Early pressure decline was slower than predicted; material balance indicated that a higher STOOIP was needed as stronger aquifer support alone was not sufficient to match observed pressures. Late field life data showed a more complex situation, indicating an even stronger aquifer than had been previously modeled. The impact of aquifer strength on pressure support was not fully recognized at project funding time. For most subsea developments with limited ability for well intervention, reservoir surveillance data from permanent down-hole pressure gauges and particularly 4D seismic are critical to effective reservoir management. Learnings from this field have been applied to other West African deep-water developments.
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3D Reservoir Geomechanics Workflow and Its Application to a Tight Gas Reservoir in Western China
Authors Kaibin Qiu, Ning Cheng, Xiangui Ke, Yang Liu, Lirong Wang, Yingru Chen, Yong Wang and Pi XiongEasy oil has gone and now the focus of exploration and development in China has shifted to tight reservoirs deemed techanically challenging. One of the key challenges in tight reservoirs is how to place and land horizontal wells in sweet spots (with high reservoir quality and completion quality) and how to stage-fracture these wells efficiently to produce these tight reservoirs economically. The paper presents a new 3D reservoir geomechanics workflow that has been applied to a tight gas reservoir in western China. The reservoir is very deep (up to 4500m) and the production rates from the wells are very low. Some hydraulic fracturing had been conducted for vertical exploration wells but the post-fracturing production rates were still not satisfactory. The best chance to produce this tight reservoir is to place horizontal wells in the areas with the best reservoir quality and completion quality and carry out optimized multistage hydraulic fracturing. To this end, a 3D full field geomechanics model was constructed through integration of seismic data, geological structure, core data and log data. This 3D geomechanics model enables a 3D identification of the high completion quality (high fracturability) zones in the reservoir and subseqently placement of a new horizontal well. A 1D mechanical model was then extracted along the planned trajectory from the 3D geomechanics model. Based on the 1D geomechanics model, optimization of the stage-fracturing design was conducted to obtain the optimal number of stages, optimum fracture half length and optimum staging.
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Forming Mechanism and Petroleum Geological Features of the Western-Central African Rift Basins (WCARBs)
Authors Xiao-hua Pan, Sheng-qiang Yuan, Zhi-feng Ji, Guang-cheng Hu and Li LiuWith the exploration activities of China National Petroleum Corporation (CNPC) in Sudan, Chad and Niger, more and more 2D, 3D seismic data had been required, a series of exploration and appraisal wells had been drilled, and more of other geologic materials had been obtained, such as well logs, core, geothermal gradient data, geochemistry data etc. Based on these abundant data and integrated application of geophysics method, physical modeling, computer modeling and geological analysis etc., the authors carried out an in-depth study on the Western-Central African Rift Basins (WCARBs), coming up with an understanding that the Basins are of passive rifts different from the so-called active ones formed in result of mantle up-welling. The WCARBs present unique petroleum characteristics including low geothermal gradient, aggregate thin-bedded hydrocarbon source rocks in syn-rift sequence, small-scaled post-rift sequence and high-angle basin-controlling major faults etc., and as a result, exhibit petroleum systems with unique characteristics, such as late and long-lasting oil generating window, high oil-expulsion efficiency, and fault-block dominated traps with rare rollovers etc. The deep study and analysis of the basin structure, sedimentary features and petroleum system obviously enhance the exploration discovery of WCARBs, which is the key factor of the successful E&P activities of CNPC in WCARBs.
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Depositional and Diagenetic Sedimentological Model of Najmah-Sargelu Formation, Umm Gudair, Kuwait
Authors D. Singha Ray, A. Al-Shammeli and W. Al-KhameesNajmah-Sargelu Formation of Middle Jurassic is tight, fractured Carbonate reservoirs, spread across many fields in Kuwait. These reservoirs are often vertically and laterally heterogeneous because of depositional variability and diagenetic alteration through space and time. Understanding the distribution of hydrocarbons in relation with porosity / permeability heterogeneities is thus of major importance in effective field development and production. A proper sedimentological model is then a mandatory step in matrix characterization to make an accurate numerical reservoir model, predicting fluid flows through time in order to support development scenarios. This paper presents an overview of efforts in building a sedimentological model based on the analyses performed on cores penetrating the Najmah and Sargelu Formations of the Umm Gudair field. The data obtained from the description of cores allowed defining a sedimentary facies scheme that served a basis for building of a 3D sedimentological model. Dominant sedimentary structures and bioturbation traces have been taken into account for the facies classification. The apparent differences in texture between the core-based lithotype scheme and the thin-section based microfacies scheme is due to intense micritization of grains. This model shows a moderate-energy carbonate ramp with a relatively flat morphology, further subdivided into three major depositional environments: The mid ramp, outer ramp, and basin. The basin includes: evaporitic conditions, restricted/anoxic conditions, unrestricted/oxygenated conditions. The basinal deposits are mostly characterized by shaly mudstones that host the deposition of a calciturbidite sheet complex. The mid- and outerramp settings are mostly dominated by relatively fine sedimentary textures where the structures are obliterated by intense bioturbation.
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Enhancing Accuracy in Carbonate Characterization and Evaluation of Formation Sands in the Presence of Clay and Feldspars using Multiple Analytical Methods: A Case Study
By JaJati NandaKnowing the exact mineralogical composition of the formation sand is very important for well treatment designs. Acidizing treatments are designed with various concentrations and mixtures of acids, depending on the composition and concentration of carbonate minerals, such as calcite, dolomite, siderite, and ankerite, in the formation. Accurately identifying carbonate systems in the presence of clay minerals (i.e., muscovite, illite, kaolinite, chlorite, smectite, and mixed layer) and feldspars (i.e., albite and microcline) is always a challenge. To meet this challenge, X-ray diffraction (XRD) analyses based on Rietveld and external standard methods have been widely used to determine the mineralogical compositions of samples. But accuracy of the results depends on various factors, such as the crystalline nature of the sample, the presence of an amorphous inorganic phase, and the presence of organic materials. Sample preparation, sample packing, and even human error in phase identification are also factors responsible for inaccuracy in compositional study. This paper describes an attempt to enhance the accuracy level in analyzing formation samples containing clays, feldspars, carbonates, and quartz with the help of combined analytical methods, such as XRD, thermal gravimetric analysis (TGA), and acid solubility. Some differences were observed during the initial XRD study of the samples and acid solubility data, and the differences were greater with increased concentrations of clay and feldspars in the sample. Hence, for better calculation of carbonate minerals present in the sample, the result from TGA was taken into account. The results derived from TGA were shown to be in line with the solubility data. Final interpretation was drawn on the basis of the combined data obtained from XRD, TGA, and the solubility analysis. For confirmation, the resulting filtrate from the acid solubility test was analyzed using the inductively coupled plasma (ICP) method, and the output data helped in calculating the final concentration of soluble components.
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Advances in Technology of CBM Horizontal Well Completion in Deep Area
Authors Zhengrong Yuan, Martijn Kleverlaan and Jinpo DongIn 2011, a deepest horizontal Coalbed Methane (CBM) well in China, with a total vertical depth in excess of 1100m, was successfully drilled by Shell China E&P Co. Ltd (SCEPCo). The well, located in the East Ordos Basin, achieved a total ‘inseam’ length of nearly 3600 m. The integration of technology across multiple disciplines, which enabled this well to be a success, is presented in this paper. An integrated geological evaluation of both regional and block scale data was used to map the depth, continuity, thickness and gas content of the coal seams. This evaluation, together with understanding of structure and distribution of faults, was then used to pick a well location in an area where the coal seams are thick and the gas content is high. The uncertainties in the evaluation are greater where the coal seam is deeper and include factors such as the stress field, coal mechanical properties, structural complexity of the seam, presence of a roof aquifer and the permeability.When planning the drilling of the well, a comprehensive drilling strategy, together with sidetrack and drilling fluid programs were prepared prior to the campaign. This preparation was invaluable for successfully drilling the first horizontal well despite the geological uncertainties present. The MWD technology and expertise in geosteering were also essential to successfully drill the horizontal laterals in this area as there is a potential aquifer in the limestone roof which needs to be avoided and there are kink bands in the coal seams. A geomechanical evaluation was also completed to understand the stress field and the orientation of fractures in the coal seam. This is required to understand and balance the trade-off between orienting the horizontal laterals to maximize production against maintaining the stability of the well bore. After completion of the well, the well production was initially affected by several shut-ins which delayed gas production. A combined dewatering and control system was then adopted which was shown to effectively mitigate fluid level buildup issues arising from unexpected workovers and well shut-ins. In conclusion, this well demonstrated the feasibility of drilling horizontal CBM wells in the area deeper than 1100 m and it is expected that this technology can be applied in the near future to unlock the potential of other deep CBM opportunities in China.
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New HTHP Cutter Technology Coupled with FEA-Based Bit Selection System Improves ROP by 60% in Abrasive Zubair Formation
Efficiently drilling the abrasive Zubair sandstone is one of the Middle East’s most daunting challenges. Adding to application complexity, the pyritic formation is also interbedded with hard shale streaks and has a compressive strength that ranges between 3-10kpsi. In Kuwait, the formation is first encountered at a depth of approximately 9000ft and been drilled with mixed performance results based on bit diameter. Generally, the large diameter PDC bits are still struggling to achieve the durability objective with some wells requiring more than two PDCs to complete the short 1400ft hole section. In the smaller hole sections, technological advances have overcome the cutter/bit durability issue but with no significant improvement in ROP. The objective of an intensive bit optimization effort has focused on increasing penetration rates while striving to improve overall bit life/cutter durability. To accomplish the operator driven objectives without time-consuming field trails, the drilling team used a software system to calibrate rock strength. This data was used in conjunction with an advanced FEA-based modeling system to analyze different PDC cutting structures to select a PDC bit with the blade count and shearing configuration that would produce dynamically stable drilling. The bit body would be equipped with a new O2 cutter to increase abrasion resistance and maintain temperature at the cutter tip by using: 1) enhanced HTHP sintering process; 2) refined post-pressing process to improve thermal stability 3) optimized hydraulics to maximizing cutter cooling. The authors will discuss the bit selection process and modeling system which eliminated costly field trials and the new manufacturing processes that produced the HTHP cutter technology that increased ROP by 60% in the 8-1/2” hole section. The new PDC bit achieved the operator’s objective of drilling shoe to TD eliminating several trips for new bits while delivering a significant reduction in drilling costs.
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Integration of 3D Modeling and Real-time Processing for Enhancement of Anisotropic Formation Evaluation with Borehole Multicomponent Induction Measurements
Authors Junsheng Hou, Luis Sanmartin and David TorresIt is well known that around the world a number of oil and gas reservoirs consist of formations which are identified as resistivity/conductivity anisotropic by borehole induction tools, such as thinly laminated sand-shale or bedded sand-sand rock sequences. Therefore, resistivity-anisotropy formation properties are critical for accurately evaluating anisotropic reservoirs. For many years the logging industry has tried to use induction tools to measure both horizontal and vertical resistivities of reservoir formations. As one of the latest and most remarkable developments in the wireline induction logging domain, multicomponent induction (MCI) logging is now used to fill this requirement. Compared to conventional induction, this new logging technology is able to measure the formation anisotropy (vertical and horizontal resistivities, Rv and Rh, respectively), dip, and strike required to accurately evaluate different types of anisotropic reservoirs. When interpreting MCI data for the purpose of anisotropic formation evaluation, most cases theoretically require 3D electromagnetic (EM) forward modeling and inversion. However, experience has clearly shown that the current 3D forward modeling algorithms often fail to obtain accurate solutions in a reasonable amount of CPU processing time. Even for the most efficient algorithms, fully 3D inversion is impractical for the real-time or well-site delivery of inverted results from measurements. For fast and accurate 3D EM forward modeling, a practical 3DFD (finite difference) method based on an isotropic/transverse isotropic (TI) background is presented and used. This method has been tested by fast borehole-effect correction (BHC) and several independent 3D codes. Its practical application workflow is also proposed and tested. The timeconsuming 3D inversion is generally partitioned into a few simple and fast data processes including resolution enhancement of MCI logs for reducing shoulder-bed effects and a few low-dimensional inversions such as radially one-dimensional (R1D) inversion, which makes possible the real-time delivery of formation anisotropy (Rh and Rv), dip, and strike information. Moreover, the R1D inversion is based on a fast and rigorous multistep inversion algorithm and a fast forward modeling engine which consists of the pre-calculated MCI-response library created by using the fast 3DFD method. This novel method of integrating 3DFD numerical modeling and real-time processing technologies has been proposed and implemented for enhancing anisotropic formation evaluation. To demonstrate its capability and effectiveness, we successfully validated the method on both synthetic data and field log data sets.
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Multiphase (Oil-Water) Flow Loop Test for Helical and Hybrid Passive Inflow Control Devices
Authors Byung O. Lee, Majed N. Rabeh, Roberto Vicario, Paolo Gavioli and Gonzalo GarciaTo address the need for better understanding of multiphase fluid flow behavior through passive inflow control devices (PICDs), two-phase (oil-water) full-scale flow loop testing on helical and a new ICD design, “Hybrid” has been completed. The primary testing objective was to generate a comprehensive two-phase (oil-water) data set of flow performance curves for the helical ICD and the hybrid ICD. The test included a broad range of flow tests with varying viscosities, water cuts and pressures. The results are presented in an innovative manner using isobaric plots (isobars lines with trend lines for each viscosity value) and Reynolds number vs. Flow Coefficient plots, which can be used to easily compare different ICD performances. Test results confirm that for oil-water flow, a viscosity break point for the helical ICD occurs at 2 centipoise (cP) of medium oil. Below this break point the helical ICD does not promote water production in two-phase flow. Above this viscosity break point, the helical ICD exhibits a physical phenomenon where, at water cuts above 30%, the total flow increases at any given pressure drop promoting water flow. With regards to two-phase oil-water fluid flow, the hybrid ICD performs independently of viscosity for the range tested (up to 200 cP – maximum flow viscosity tested at the lab). The hybrid ICD consistently creates more resistance to water flow than to oil flow, causing total flow to gradually decrease at constant pressure as water cut increases. This effect was more apparent at higher pressure regimes. The functional break point of the hybrid ICD is determined to be above 200 cP.
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Well Integrality Technical Practice of Ultra Deep Ultrahigh Pressure Well in Tarim Oilfield
Authors Zhang Fuxiang, Yang Xiangtong, Peng Jianxin, Li Ning, Lv Suanlu, Zeng Nu and Zhang RixingThere is abundant natural gas in Kuqa foreland area of Tarim basin, it has characteristics of reservoir burial depth (5500-7500m), high gas reservoir pressure (105-125Mpa), complex corrosive medium (the partial pressure of CO2 is beyond 2 Mpa, the chlorinity is between 100000 ppm and 140000ppm), and the overburden lithology of gas reservoir is complex (there is heavy calcium rock and mudstone layer), which bring well integrality high challenge. During over three years practice, through exploring the extreme high pressure down hole string shock checker, tubing tongs torque field proving, establishing extreme high pressure complex corrosion behavior pipe simulation behavior laboratory evaluation criterion, supporting air spider and threaded He gas tight detection device, several techniques are formed initially including extreme high pressure gas well pipe simulation behavior evaluation technique, extreme high pressure gas well wellbore evaluation technique, extreme high pressure gas well string layout and mechanical check technique, completion string quality control technique, it provides dynamic guarantee for long-term secure manufacture in Kuqa extreme high pressure extreme deep gas reservoir.
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High-Strength, High-Stability Pill System to Prevent Lost Circulation
Authors Cheng-yuan Xu, Yi-li Kang, Li-jun You, Song Li and Fei ChenA new high-strength, high-stability (HSHS) pill system for controlling lost circulation has been developed and optimized on the base of a physical model of stable plugged zone. This new HSHS pill system provides a stronger and more effective seal than traditional treatments. Controlling lost circulation with plugged zone formed with lost circulation material (LCM) in the fracture has achieved tremendous success in the past years. However, investigation into the strength and stability of the plugged zone has not been reported. Ignorance of such knowledge often leads to excess costs from repeatedly fluid loss and rig time, increases the difficulty and complexity of loss-zone diagnosis. The new HSHS pill system addresses these shortcomings. Surface friction coefficient, LCM volume fraction and amount of contact deformation are the main influencing factors of the strength and stability of the plugged zone. The strength of the plugged zone is enhanced with the increase of the above factors considering which the physical model of stable plugged zone is established. The pill system based on the model provides an engineered combination of rigid granules, fibers and deformable particles. The sealing efficiency and the pressure-bearing capacity are greatly enhanced. It was validated in several field trials in West China. Operational practices that facilitate the safe use of the HSHS system with overbalance exceeding 2,174 psi are discussed. In addition to the field trial results, this paper also described the laboratory-scale tests, which were used for developing the new system. With the development of the physical model and the HSHS pill system it is now possible to optimize and select the types, properties and matching relations of the LCM. This technology can also be used to guide the design of wellbore strengthening scheme and make sure the long-term effectiveness of wellbore strengthening measures.
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Methodology to Estimate the Optimal Production Rate and OWC Advance in Naturally Fractured Reservoirs in the South of Mexico
Authors C.J. Lárez, J.E. Paredes, J.L. Fong, L.M. Perera and R. PérezA great problem of naturally fractured reservoirs is the abrupt irruption of water in wells. To predict this behavior, a methodology that uses numerical sector models and discrete fracture Network (DFN) was designed; so-called Pseudoradial models (PRM). These models were calibrated to match the water invaded wells production history and subsequently it was applied to proposed or new wells. This methodology was used successfully in Pijije field, Mexico. The first pseudoradial models were generated in the Pijije field due to the abrupt water irruption problem it presented. Three well models were built based on the calibration of the model built for the Pijije-101 well. The DFN was generated from average characterization of fractures obtained from FMI logs and general input from the field pressure and production behavior. Once the variables of uncertainty were analyzed, a conventional radial model was initially built and calibrated with the historical production and pressure profiles. To achieve this match, the values of porosity in both systems (matrix and fracture) were changed drastically and the water front advance resulting was homogeneous and only present a coning phenomenon when the OWC reaches a minimum distance of 200 meters from the well. The second part of the analysis was carried out with the pseudoradial model; in this case, the parameters with greater impact were the characteristics of discrete fracture network. The pseudoradial model managed to reproduce the well production and pressure history. Analyzing the results, it was concluded that both scenarios were acceptable. Reviewing the water advance fronts in both cases, the pseudoradial model did not have a uniform front of OWC advance and showed areas not drained (corresponding to present or absence of fractures) and the water moves through the preferential fracture channels represented by the DFN in the model.
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Multizone Tight Gas Completions in the Piceance Basin: Over a Decade of Learnings
Authors Ajibola Adeyeye, Romeo Perez, Melanie Boyer and Deni WielandIn 1999, tight gas development began in Piceance Creek area of the Piceance Basin, Colorado by utilizing a new technology to individually fracture-stimulate over 50 stacked tight gas sand packages, spanning as much as 5000 vertical feet in each well. Through the completion of over 300 wells, the Just-in-Time-Perforating (JITP) technology matured and the efficiency of completion operations improved dramatically with the implementation of simultaneous operations, refined diversion techniques, optimization of the frac design, and improved water handling. Many of these improvements can be attributed to the unique advantages of the JITP process itself. For example, the low daily water requirement enabled the use of a fully closed-loop water recycling and distribution system. This system delivers 100 percent of the requisite water to each frac site with minimal trucking and minimal storage on location, which reduced the overall environmental footprint. The project also heavily relied on a systematic science-based approach to optimize completion design. Statistical methods were used to deduce the impact of various fluid systems, chemicals, sand and water volumes, and other parameters associated with successful well stimulation. To improve long-term well productivity, a fit-for-purpose logging program was developed to identify and avoid sands with high risk of significant water production. The relentless focus on continuous improvement over the last several years resulted in notable reduction in completions cost per unit gas.
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Acquiring and Maintaining Social License to Operate for a Major LNG Project in Papua New Guinea
Authors James W. Canning, Ian Marru and Kenneth W. WaltersLegal license to design, construct, and operate a major project in any country is granted by the government and regulatory bodies of the respective country. Such is the case with the PNG LNG Project currently being built by ExxonMobil and its co-venturers in Papua New Guinea (PNG). The Project, which includes gas wells, a 960 MSCFD gas conditioning facility, a 300 kilometer onshore pipeline, a 400 kilometer offshore pipeline, and a 6.9 Mta LNG plant, would be a major challenge in any country in the world. Government and regulatory approvals were granted in 2009 in order for design and construction to begin, and the project is on track to start up in 2014. However, a significant hurdle to building the project and operating it for 30+ years is acquiring and maintaining the social license that is “granted” by the indigenous people of PNG who live in the project impacted areas. In a country of almost 7 million people speaking over 800 different languages and living a largely subsistence lifestyle, the Project represents an opportunity to improve their lifestyle and and allow government to fulfill promises and commitments that have been made by governments over many years. The indigenous people use a variety of techniques to negotiate and frequently stop work and hinder progress in order to have their voices heard and their demands addressed. In order for the PNG LNG Project to be a long term success in Papua New Guinea, a comprehensive strategy for acquiring and maintaining social license to operate had to be developed and implemented. This paper will define what is meant by social license to operate (SLO), discuss the business drivers of SLO and why it is important to manage it with the appropriate people, skills, and strategies, describe ExxonMobil’s approach to acquiring and maintaining SLO in PNG, and offer some lessons learned.
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Unlocking Reserves, Fracturing Tight Gas-Condensate Bearing Sandstone: The Base History of a North African Field (Algeria)
Hydraulic fracturing technique is worldwide used to unlock reserves in tight formations. The Devonian layer, present in this field in the Berkine Basin (Algeria), is gas condensate bearing with a permeability range of 1 to 0.1 md; the zone shows also an highly tectonic stresses, and the frac gradient can rise easily values above 1.0 psi/ft. 3 previous fracturing treatments performed in 2005 and 2006 in 3 vertical wells were without success, due to the high stresses encountered, the wrong frac designs and completion limitation. Aim of this paper is describing the successful multiple propped hydraulic fracturing treatments, placed in a subhorizontal well in March 2012, listing all the actions done in terms of Completion design Materials choice and Frac schedule optimization. This paper describes also the multiple lessons learned experienced in the execution phase of the multifrac job about frac placement, frac design and completion choice, that have to be considered for the fracturing jobs already planned, in fact the good results of this treatment allowed the Operator to plan a future appraisal/development phase for the Devonian layer.
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