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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
151 - 200 of 581 results
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Drilling with Casing Technique Successfully Overcome Massive Thief Zone
Authors Diah Agustina, Erwindo Tanjung and Hafidh TaufiqurrachmanThe Lima field, located offshore in North West Java Indonesia, encountered major challenges to both drilling and cased off problematic zone during running casing operation due to severe lost circulation conditions. Specifically, severe mud losses in the major loss zone were recorded in Pre-Parigi formation. The operator has experienced massive loss problems while drilling the 8-1/2 inch section. Unsuccessful sidetracking operations with conventional drilling technique has urged operator to look for alternative drilling methods to case off the massive thief zone. The drilling with casing system has been identified as one drilling technique that may repairthe troublesome thief zone. This non-retrievable system, which utilizes casing as drill string, allows the string to immediately be cemented in place once targeted depth is achieved, hence eliminating the risk of casing tripping failure through massive lose zone with conventional drilling method. The special designed aluminum crown casing bit is drillable by subsequent section conventional bit without additional clean out trip. This paper will discuss the planning, implementation and finally the results of 7 inch drilling with casing technique through the problematic Pre-Parigi lost circulation zone.
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Upstream Stranded Raw Gas Management as Compressed Natural Gas
More LessMarine compressed natural gas (CNG) has been considered in the past as a means of natural gas transportation but proved to be a non-starter for a number of reasons including long distances or large volumes of gas when compared with liquefied natural gas (LNG). However, marine CNG still figures economically attractive over shorter voyages (up to ~4,000km) and medium volumes of gas. Recent advances in containment systems are poised to provide marine CNG with the best opportunity to be resurrected as a major enabler of new and previously stranded hydrocarbons by becoming an important optimization tool to petroleum well performance. Almost half of offshore natural gas, SEC-type, reserves are considered “stranded” because of the high unit technical cost to harness natural gas in remote locations involving deep-water and/or pre-salt basins, and the lack of a reliable and commercially viable market for the natural gas. Most of them do not contain enough gas to justify their own gas transmission solution, floating or onshore LNG production. Furthermore, inoperable gas affects oil production in many adverse ways from the logistics of handling and facilities capacity to the cost of the treatment. Marine CNG used as a wellhead fluid shuttling service for raw gas can generate significant monetary benefits for an operator attributable directly to the new technology and innovative application. Gas viewed like this is no longer a mid-stream product in need of further processing prior to sale, but becomes a potential upstream saleable product. We present here the new technology emphasizing the containment system manufactured with composite materials that are far lighter than metal and yet can withstand the 200-atmosphere pressure and corrosion from hostile raw gas composition straight out of the primary separator. CNG cargo containment system produced with composite materials can reduce overall steel weight by 50-80% and can operate with pressures ranging from 150 to 250 bars, sufficient to accommodate a wide range of gas-oil-ratios without the need of refrigeration.
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Paleogeomorphology Analysis and its Application in Exploration and Production of Karstic Ordovician Carbonate
The Ordovician carbonate karst reservoir which is usually buried 5000m deep is an increasingly important target for oil exploration and production in Tarim Basin, West China. The paleogeomorphology of the top of the Ordovician carbonate directly controls reservoir development and hydrocarbon accumulation, so detailed characterization of karst paleogeomorphology is one of the key steps to identify reservoir development rules which will lead to more efficient exploration and production activities in the study area. This paper presents an example study on carbonate karst paleogeomorphology in Tarim Basin. Also, its significance to exploration and production activities has been discussed.
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Lessons Learned from Water Shut-off of Horizontal Wells Using Inflatable Packers and Water Shut-off Chemicals in the Ghawar Field of Saudi Arabia
Authors Hemant Sharma, Jorge Duarte, Eid Mufeed, Saadoun Turki and Jose R. VielmaDue to the advancement of technology and improved capabilities of drilling horizontal wells, producers and injectors are now commonly completed with long horizontals to expose large reservoir areas. For the reservoir pressure maintenance, the most prevalent means is by using water injection. This injected water, while helping in pressurizing the reservoir, becomes a curse when it starts to produce with the oil. In addition, as the transmissibility of the water is higher than the oil, water breakthrough is a major challenge facing the oil industry. Various techniques are available and being used worldwide to control/reduce this produced water; however, controlling water production by performing water shut-off (WSO) in horizontal wells is more complicated and challenging than in vertical wells. To control water production in horizontal wells, isolation of the wellbore using inflatable packers in open/cased hole completion and capping with cement has shown little success in the past. Therefore, another technique was attempted to control water production in horizontal oil producers by using mechanical means to isolate the wellbore and chemical means to isolate the matrix/fissure, which forms a permanent barrier and reduces water production. The selection criterion for mechanical isolation and type of chemical suitable for the formation is a tedious task for the petroleum engineer. Most of the time, the vendor’s data that is available is being used and applied for the field application, which shows a low success ratio. In this paper a brief overview has been presented, taking into account two wells from Ghawar field in Saudi Arabia, where a combination of wellbore isolation using inflatable packers and matrix/fissure isolation using an organically cross-linked polymer (OCP) system were performed. The candidate selection criteria, job criteria, planning, execution, and post-job evaluation will be discussed.
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Applications of Bio and Nanotechnologies in the Oil and Gas Industry, Recent Progress, Applications of Composition Deflecting Flow for Increasing Oil Recovery
More LessThe efficiency of oil extraction from oil-containing reservoir is unsatisfactory all over the world. The average oil recovery among different countries is from 25 to 40%. Unrecoverable oil resources reaches up to 70% from the geological oil reserves. Besides it should be noted that major oil fields of the oil-producing country, including certainly Russia, move to the late stage of development, characterized by a passive increase in water cut and decrease of oil production. However, the oil reserves in the fields with water cut over 90% at the late stage are formidable. Therefore creating of new extracting technologies is an actual problem nowadays. For example nanoparticles with noticeable alteration in optical, magnetic, and electrical properties compared to their bulk counterparts, are excellent tools for the development of sensors and the formation of imaging contrast agents. Nanosensors deployed in the pore space by means of «nanodust» can provide data on reservoir characterization, fluid-flow monitoring, and fluid-type recognition. As for production nanomaterials-based solutions can contend with corrosive impurities, high temperatures and pressures, shock loads, abrasion, and other hostile environmental conditions. Drilling equipment and platforms can be made or coated with nanomaterials for improved corrosion-resistance, wear-resistance, shock-resistance, and enhanced thermal conductivity.
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Physical Modelling of In‑ Depth Fluid Diversion by Gel Dam Placed with Vertical Well
Authors Junjian Li, YuZhang Liu, Yikun Li and Falin WeiIn view of the ineffective cycling issue of injected water through the high permeability zones during water flooding process in positive rhythm reservoirs,the gel dam in-depth fluid diversion technique is proposed.The technique first promoted the injection of gel by horizontal or sidetracking wells drilled in the more permeable and strongly swept zones of thick positive rhythm reservoirs.The injected water then will bypass the "gel dams" and be diverted into the upper unswept or poorly swept low permeability zones.As a result,the swept efficiency and oil recovery of the upper low permeability zones can be both increased. Gel dam placement method can be enhanced the oil recovery both in the laboratory experiments and numerical simulation technology, but the use of new drilling horizontal wells for gel dam placement accompany with certain technical and economic risks;In order to reduce risk, to explore the law of horizontal well gel dam placement, we proposed the use of the crossing straight well set to place the gel dam for Daqing Oilfield, which is consistent with the current research status.Straight and horizontal wells gel dam placement have the similar principles, but there are some differences, how to use a crossing well to place the gel dam should be further study to improve the development effectiveness. The physical modeling experiments of gel dams in a positive rhythm formation and in a point bar sand body are conducted in the 3D physical model. The results of the experiments indicated that,with one or two gel dams, the sweep volume and ultimate oil recovery were both increased greatly,and the water cut ascending velocity was decreased. Compared with the physical model with horizontal gel dam,the ultimate oil recoveries of those with gel dams decrease by 8.1,but the oil recvoery is still 7.6% higher than water flood .By vertical well "gel dam" in-depth fluid diversion technique, the difficulties in the in-depth placement of plugging agents will be solved, risk has been reduced and the swept efficiency of positive rhythm reservoir can be increased significantly.
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Oil-Based Fracturing Fluid: First Results in West Africa Onshore
Authors R. Perfetto, R.C.B. Melo, F. Martocchia, R. Lorefice, R. Ceccarelli, L. Tealdi and F. OkassaHydraulic fracturing operations in West Africa are not as common as in the US, Latin America and the Middle East. In the Republic of Congo fracturing technology is spreading and has overcome more than few difficulties since the practice began. The most significant challenge has been the formation, which has shown through laboratory testing to be soft and watersensitive. The fracturing project started in the laboratories, identifying critical issues, such as formation heterogeneity, hardness, water sensitivity, clay content and particularly the risk of proppant embedment. The fracturing fluid chosen for the project was a water-based, borate-crosslinked guar fluid, with specific chemicals added to minimize formation softening and clay swelling issues. A specific pumping strategy was implemented when using waterbased fracturing fluid to limit the effects of proppant embedment. Several wells were treated with this system. In an effort to improve well productivity, a pilot test was designed with oil-based fracturing fluid. This fluid was pumped in two wells, resulting in improvements in terms of cleanup time and economics, compared to the water-based treatment fluids in the same field. Part of the economic benefit was gained because of the reduced hydrostatic head of the oil-based fracturing fluid, which eliminated the need for a coiled tubing gas lifting operation. Economics were also improved by minimizing rentals of well cleanup equipment because the broken fracturing fluid can be sent directly to production facilities. In this paper, design and application results for the oil-based fracturing fluid operations are presented with all the operational and logistical challenges overcome.
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A Successful Application of 3D Seismic Attributes in Exploration for Eolian Stratigraphic Traps in Central Saudi Arabia
Authors Herbert Hu, Mohammed Saeed Al-Zahrani and Khalid Al-MahmoudThe purpose of this presentation is to demonstrate the successful application of 3D seismic attributes in exploration for Permo-Carboniferous eolian stratigraphic traps in central Saudi Arabia. To explore for these traps, we have integrated regional geological studies and rock property analysis, and tied these to the seismic attribute response. Permo-Carboniferous eolian reservoirs are the primary objective for oil and gas exploration in central Saudi Arabia. Due to the nature of the mixed fluvio-eolian setting, this is a very challenging target, especially for stratigraphic traps. The eolian setting comprises a complex mix of depositional systems including eolian ergs, ephemeral streams, and ephemeral (playa) lakes. Eolian sand dunes and sand sheet deposits are the two main reservoir facies, while lateral facies changes result in the primary up-dip seals.
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Cementing Through Capillary Tubing to Meet Regulatory Requirements: A Novel Approach for Plug and Abandonment
Authors Jason Wilde and Todd EllisCapillary tubing has traditionally been used for various downhole chemical treatments applied to enhancing fluid loading, treating corrosion and scale buildup, and preventing paraffin and emulsion formation. Capillary tubing provides an advantage over coiled tubing due to its lighter weight, smaller footprint, mobile structure, faster running speeds, and more economical costs. One drawback however, is the increased friction pressures when pumping abrasive fluids. Typical capillary tubing is sized from ¼ to ¾ in. OD versus the more common coiled tubing, which ranges from 1 to 3 ½ in. OD. Therefore, the use of capillary tubing for cementing operations has not been considered until recently. This paper will feature a project in Australia where a capillary unit was employed to abandon a well with cement, while concurrently installing downhole pressure gauges to comply with local regulations. The cement design criteria along with two case histories will be described, and lessons learned will be evaluated. Data that has been collected through the various jobs will demonstrate that current simulation software will need to be modified to match pressure outputs witnessed in the field. A comparison of simulated versus actual job pressure data has shown as much as a 70% friction reduction in actual pressure readings. The witnessed pressure values are shown to be consistent over several operations; therefore a theoretical correlation can be drawn so more realistic values can be simulated in the future. Additionally, slurry designs which were proven successful and operational considerations for improved job quality will be discussed. This paper will discuss two case histories in which capillary tubing was used for the first time in Australia. Methodology, limitations, and future improvement possibilities will be discussed in detail throughout this paper.
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Multi-Tubular Corrosion Inspection using a Pulsed Eddy Current Logging Tool
Authors Marvin Rourke, Yong Li and Glyn RobertsTubular inspection can be split between direct measurements such as caliper logs or downhole video observation and Electromagnetic (EM) methods that measure properties sensitive to pipe thickness, with wall thinning associated with corrosion and other pipe defects. Various EM methods have been reported over the years often initially for pipeline inspection and then adapted for downhole well monitoring. These methods include Magnetic Flux Leakage (MFL) and Eddy Current (EC) measurements. Early EM methods were single frequency but later developments include multi-frequency. In this paper we report an emerging technique called Pulsed Eddy Current (PEC) which is inherently multi-frequency and in time domain is radially sensitive which enables inspection of multiple tubular thicknesses. Most inspection techniques including some EM methods are only capable of inspecting the inner most tubular or only the total thickness of multiple tubulars. However, a PEC tool can measure separate thicknesses of both inner and a second tubular. This allows quantitative corrosion evaluation of casing without removing the completion tubing. The paper covers a theoretical review of the PEC technique and development of a fast forward analytical model tied to experimental data acquired with an actual logging instrument. The fast forward model is used to ensure optimum tool design and allows development of an inverse model which realises quantitative evaluation of the corrosion within multiple tubulars from field data.
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Asset Integrity Challenges in Oil & Gas Process Facilities
Managing asset integrity is a complex activity in surface production facilities of an oil industry. Process equipment in an oil production facility is exposed to various damage mechanisms that may be active due to the presence of contaminants in the process streams. Proper material selection, maintenance programs, inspection monitoring and repair are the standard components of the Asset Integrity Management Process. The conventional way of approaching the problems caused by damage mechanisms such as Hydrogen Induced Cracking (HIC) and Stress Corrosion Cracking (SCC) in Pressure vessels is by way of repairs or replacements. Black powder deposits are also causing increasing concerns due to fouling and severe corrosion. One pressure vessel and one heat exchanger have been replaced in few facilities of Kuwait Oil Company during the past one year due to Hydrogen Damage and fouling. One more vessel with minor embedded defects is under inspection monitoring and engineering evaluation. Alternate remedies have been applied to minimize propagation of defects. This paper presents field experience and application of various inspection methods in detecting embedded defects, hydrogen induced damages in the early stages, application of preventive measures to extend asset service life and asset integrity. Under this process, various advanced NDT inspection techniques were applied to detect and monitor critical internal defects on pressure vessels. Root cause analysis, fitness for service (FFS) and Risk Based Inspection (RBI) study have been conducted as a part of mitigating risks and applying remedies.
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A Methodology For Rapidly Predicting And Minimising Solid Particle Erosion in Oil-Gas Equipment
Authors Chong Y. Wong, Christopher B. Solnordal and Joan BoulangerSolid particle erosion in exploration and production equipment poses an inherent risk to all oil and gas facilities. As such, preemptive measures need to be employed to predict the longevity of these equipment. This paper presents a methodology to rapidly focus on the qualitative erosion hot-spots and to quantify the local erosion rate on a specific equipment both experimentally and numerically. A qualitative multilayer paint erosion modelling is first applied to the object of interest. This assumes that erosion of the paint surface is similar to the erosion rate trend of the target metal of interest. This is followed by quantitative surface profile measurements in the vicinity of the erosion hot-spots. Computational fluid dynamic (CFD) simulation of the particle flow path and subsequent impacts on the parent surface is conducted. However, prior to conducting the CFD simulations, an empirical erosion sub-model is required. This sub-model is obtained by fitting empirical curves to data obtained from physical erosion of cylinder-in-pipe samples. Once validation with experimental data is achieved, optimization can be made using computer-aided design and CFD to minimise or eliminate the erosion hot-spots. The present paper illustrates this technique via simple flow configurations commonly occurring in exploration equipment and production pipelines.
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An Insightful and Robust Approach for Multi-Tool Interpretation: Moving Away from Traditional Black Box Methods
Authors Vivek Anand, Robert Freedman and Chanh Cao MinhIn this paper a new approach for joint interpretation of petrophysical measurements acquired by multiple sensors or tools is demonstrated. This approach is based on a mapping function that can be expressed as a linear combination of radial basis functions (RBFs). The theoretical log response equations for the sensors or tools are used to compute a database covering all possible ranges of formation properties, i.e., the solution space. The database is used to construct the mapping function that relates log measurements to formation properties. The solution space can be plotted in 2D or 3D depending on the number of input measurements. The plots provide the petrophysicist with a useful tool to: 1) identify outliers that might denote a model inadequacy, 2) select appropriate equation parameters that might not be obvious from individual logs, and 3) compute a solution consistent with the model equations. The mapping function solutions are computationally fast, unique, and robust. In contrast, traditional multi-tool interpretations based on non-linear minimization techniques often face problems of non-uniqueness and lack of robustness. We demonstrate the new approach using two classic examples. The first is the integration of resistivity and pulsed neutron capture logs to solve simultaneously for water saturations and salinities. This is a non-linear problem that has complex input parameter dependencies. The second example is analysis of thin-beds that have resistivity anisotropy. Even though analytical solutions exist, they are complex and it is difficult to see how, for example, net pay depends on the anisotropy. The choice of these classic examples allows us to show the simplicity of the proposed technique and to benchmark it against the traditional methods.
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Advanced Reservoir and Tar Mat Evaluation Using Downhole Fluid Analysis and Asphaltene Flory-Huggins-Zuo EoS
Authors Julian Y. Zuo, Oliver C. Mullins, Vinay Mishra, German Garcia, Dan Zhang and Chengli DongAdvances in asphaltene science and a new generation of downhole fluid analysis (DFA) technology have been integrated to yield powerful new insights to reservoir dynamics. The Yen-Mullins model of asphaltene nanoscience has enabled development of the industry’s first predictive equation of state (EOS) for asphaltene concentration gradients - the Flory-Huggins-Zuo (FHZ) EOS in oil reservoirs. The FHZ EOS along with DFA measurements has successfully addressed a variety of reservoir concerns including reservoir connectivity, viscosity gradients, and fluid disequilibrium. The model shows that asphaltene concentration gradients can be large owing to both the gravity term and gas/oil ratio (GOR) gradients. The FHZ EOS is reduced to a very simple form for low GOR black oils and heavy oils, and heavy oils are shown to exhibit enormous asphaltene concentration gradients compared to conventional black oil. In this paper, the FHZ EOS has been applied not only to calculate asphaltene concentration gradients but also to predict asphaltene phase instability in oil reservoirs and potential flow assurance issues. Two categories of tar mats are addressed, one with a large discontinuous increase in asphaltene concentration versus depth typically at the base of an oil column (corresponding to asphaltene phase transition); the second with a continuous increase in asphaltene content at the base of a mobile heavy oil column due to an exponential increase in viscosity with asphaltene content. The discontinuous type of tar mat is show to occur in two distinct setting, one more common tar mat at the base of the column and a second unusual tar mat that occurs upstructure and is permeable. The predictions are in good agreement with the laboratory and field data and the mechanisms of forming these two kinds of tar mats are also discussed. This methodology establishes a powerful new approach for conducting the analyses of asphaltene concentration grading, flow assurance and tar mat formation in oil reservoirs by integrating the Yen-Mullins model, and the FHZ EOS with DFA technology.
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Initializing Dynamic Reservoir Models for History Matching Using Pre-Production 3D Seismic Data
Authors Mohammad Emami Niri and David LumleyStochastic reservoir modeling is a common practice in the energy industry, and is widely used for hydrocarbon reserves estimation, targeting new producer/injector locations, and production profile forecasting with flow simulators. Due to its high spatial coverage, 3D seismic data plays a critical role for defining the reservoir geometry, and for constraining physical property modeling. However, integration of 3D and time-lapse 4D seismic data into the reservoir model history matching process poses a significant challenge due to the frequent mismatch between the initial reservoir model, the reservoir geology, and the pre-production (baseline) seismic. Therefore, a key step in a reservoir performance study is the preconditioning of the initial reservoir model to equally honor both the geological knowledge and the baseline seismic data. In this study, we investigate issues that have a significant impact on the (mis)match of the initial reservoir model with the geological and geophysical data. Specifically, we address the following questions: Which of the common methods to stochastic litho-facies modelling produce reservoir models that best match the baseline 3D seismic data after seismic modelling? How are the results affected by the presence of noise in the observable data, and by the low vertical resolution of seismic data compared to logs? What is the effect of geostatistical variogram parameters on the results? How do these methods perform on object-oriented reservoir models? The results of this study indicate that a method based on the probability of litho-facies distribution given by P-wave impedance in a stochastic modeling process yields the best match to the reference model, even in the presence of noise in the dataset. The effect of variogram parameters on the seismically-constrained litho-facies modeling process is also demonstrated.
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Comparative Study on Stress-Dependent Permeability of Ultra-low Permeability Sandstone Rock using Different Types of Fluid Media
Authors Sun Junchang, Yang Zhengming and Teng QiDuring the production lifecycle of a reservoir, rock permeability may change due to the increase of the effective stress which could significantly affect well productivity. The main objective of this paper was to investigate stress-dependent permeability of ultra-low permeability reservoir rocks using different types of fluid media. Meanwhile, wettability and its effect on stresssensitivity permeability were also studied in this research. A total of twenty-seven sandstone rock samples selected from Daqing oilfield reservoir rock and Changqing outcrop rock was used to conducted permeability stress-sensitivity experiments. The gas permeability of those rock samples ranges from 0.0029mD to 7.7603mD. Experimental results indicate that gas permeability, brine permeability and oil effective permeability at irreducible water saturation all decrease with the increase of the effective stress. Most of the reduction of gas permeability and oil effective permeability takes place over the range of 2 to 16MPa effective stress. Comparative results show that reduction of brine permeability is larger than that of gas permeability over the same range of effective stress when the rock gas permeability is greater than 1mD. However, decrease of gas permeability is larger than that of brine permeability when rock gas permeability is less than 1mD. The oil effective permeability is more stress-sensitivity than gas and brine permeability. Reduction of the oil effective permeability is much greater with the increase of the effective stress when the rock samples have been aged in crude oil. This research suggested that it may lead significantly error when gas was used as the fluid media in evaluating permeabilitydependent of ultra-low permeability reservoir rock and its effect on well productivity. In addition, reservoir wettability should be considered when oil was used as the fluid media in permeability stress-sensitivity evaluation experiment.
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Harnessing Multiple Learning Styles for Training Diverse Field Personnel in Conventional Coring Operations
Authors Roger K. Lee, Patrick M. Strike Jr, Carlos D. Rengel and David B. SuttoCoring is a critical operation for geologists and petrophysicists to accurately determine the amounts of hydrocarbons in a reservoir. Conventional coring is the acquisition and recovery to surface of a continuous column of reservoir formation material. This important information assists in determining the amount of oil and gas in a rock and the difficulty involved in retrieving the hydrocarbons. Coring requires use of special drillstring with inner and outer barrels. Additionally, the performance metrics for coring are vastly different from drilling. Due to its specialty nature, it is difficult to educate new and inexperienced individuals in coring operational procedures in a classroom environment. To address the challenge, this oilfield service organization utilized a holistic approach to develop a training course for conventional coring. Content required for the course included product functionality, rig operations procedures, and troubleshooting application challenges. The key deliverable was to meet the growing learning demands from younger generations of employees. The solution was to develop a course which encompassed multi-sensory resources including auditory, visual, and kinesthetic learning. This methodology was necessary to effectively teach a wide range of topics to a diverse population of field personnel. This paper will provide details of the innovative/new learning activities that engaged the learners and facilitated their training.
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Integrating True Valve Performance into Production System Analysis Based Gas Lift Design and Troubleshooting for Dukhan Field, Qatar
Authors Sanjay K Singh, James W Hall, Eraky Khalil, Balsam Al-Marri and Reem Al-AbdullaQatar Petroleum’s Dukhan field uses gas lift to produce oil wells that cannot sustain natural flow because of reservoir pressure decline or rising water-cut. The increasing number of wells on gas lift has made the effectiveness of gas lift design and troubleshooting a key factor to achieving crude oil production targets. Until the present day production system analysis methods were used for gas lift design and troubleshooting. This was found to be inadequate in several cases to achieve an optimum design or to troubleshoot problems successfully. To resolve such inadequacy, a new approach has recently been applied that makes use of the VPCTM (Valve Performance Clearinghouse) database. The VPCTM database provides tested or true performance data for gas lift valves. The new approach integrates well performance from production system analysis and true valve performance from the VPCTM database into an integrated system performance tool. Sensitivity analysis of the integrated system is then performed with a set of well conditions and valve parameters for gas lift design or troubleshooting. The paper focuses on the intricacies of the approach and presents a typical field example of its application. Application of this approach has enabled effective gas lift design and troubleshooting, unlocked incremental oil potential at negligible cost and extended the producing life of wells.
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Well Integrity Risk Mitigation Vis-A-Vis Revenue Potential: A Qualitative Model for Wellwork Prioritization in Dukhan Field, Qatar
Authors Sanjay K Singh, Jose Negron, Nasser Al-Marri and Nasir Murtaza ArijoQatar Petroleum’s supergiant Dukhan field located onshore Qatar has a mature well inventory of hundreds of wells. Mitigating well integrity risk without affecting crude oil production and water injection targets is critical to sustaining revenue streams from the field. This involves a large number of integrity repair wellwork with workover rigs. Performing such a wellwork campaign is time-intensive and without adequate prioritization has the potential of jeopardizing well integrity and causing safety/environmental issues besides adversely affecting the production and injection levels.This paper discusses a qualitative model that has been developed and used to prioritize repair wellwork in Dukhan field. The model is centered round integrity risk level and revenue potential of wells. A set of integrity parameters including status of surface and downhole barriers determines integrity risk level. Another set of reservoir management and well capability parameters determines revenue potential. Each of the wells is then assigned scores to reflect the risk level and the revenue potential. Cross-scaling of such scores defines the priority of a repair wellwork. Using the above approach for wellwork prioritization has been effective in mitigating integrity risk and maintaining revenue potential of the large inventory of mature wells.
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The First Land Full Azimuth Seismic for Fractured-cavernous Carbonate Reservoirs Exploration in Tarim basin, Western China
Authors Yimou Liu, Xianghao Liang, Yi Zhou, Shiyong Liu, Shangwen Lin and Naijian WangOrdovician carbonate reservoirs are the very important yet difficult targets in the oil and gas exploration and development of Tarim basin, western China. The main task (also main challenge) of seismic is to image and predict the storage spaces of carbonate reservoirs-the secondary dissolved caves, holes and fractures, which are buried in more than 6500m deep. The target formations are usually in very low signal-to-noise ratio due to the seismic attenuation and the caves and fractures are small and aligned in random directions. Narrow azimuth and conventional wide azimuth seismic fail to image and identify the fractured-cavernous reservoirs accurately, leading to many drilling failures. Here, the effects of some key acquisition parameters such as bin size, fold and aspect ratio on carbonate reservoirs imaging accuracy are carefully examined using seismic forward modeling and new analysis methods. A high-density full-azimuth seismic acquisition was carried out based on the above analysis and the results show that small bin size has the advantage to imaging the ultra-deep carbonate reservoirs and the fracture prediction results from full azimuth data well agree with that from imaging well logging data. A set of well drillings based on the full azimuth data have been proved to be successful.
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Imaging Earth's Interior Based on Adjoint Methods-Seismic Inverse Problems from Continental to Exploration Scales
Authors Hejun Zhu, Yang Luo, Ebru Bozdag, Daniel Peter and Jeroen TrompHarnessing high-performance computers and accurate numerical methods to better constrain physical properties of Earth's interior is becoming one of the most important research topics in structural and exploration seismology. We use spectralelement and adjoint methods to iteratively improve 3D subsurface images ranging from continental to exploration scales. The spectral-element method, a high-order finite-element method with the advantage of a diagonal mass matrix, is used to accurately calculate three-component synthetic seismograms in a complex 3D Earth model. An adjoint method is used to numerically compute Frechet derivatives of a misfit function based on the interaction between the wavefield for a reference Earth model and a wavefield obtained by using time-reversed differences between data and synthetics at all receivers as simultaneous sources. In combination with gradient-based optimization methods, such as a preconditioned conjugate gradient method, we are able to iteratively improve 3D images of Earth's interior and gradually minimize discrepancies between observed and simulated seismograms. Various misfit functions may be chosen to quantify these discrepancies, such as crosscorrelation traveltime differences, frequency-dependent phase and amplitude anomalies as well as full-waveform differences. Various physical properties of the Earth are constrained based on this method, such as elastic wavespeeds, radial anisotropy, shear attenuation and impedance contrasts. We apply this method to study seismic inverse problems at various scales, from continental-scale seismic tomography to exploration-scale full-waveform inversion. Two examples are utilized to illustrate the applications of this method, namely, 1) application of adjoint tomography in improving 3D elastic wavespeeds of the European crust and upper mantle, and 2) application of the impedance gradient in elastic reverse-time migration for a 2D salt dome model.
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Study on Matching Relation Between Polymer Molecular Size and Pore Size for Conglomerate Reservoir
Authors Luo Wenli, Ma Desheng, Nie Xiaobin, Lin Meiqin, Lin Qingxia, Fan Jian and Long HangThe matching relation between the molecular size of polymers and the pore size of Karamay conglomerate reservoir in Xinjiang oil field was studied. By employing the nuclepore film filtration method, core flooding experiments and dynamic light scattering method (DLS), the molecular size of several candidate polymers for the pilot test was examined. And several suitable polymers for different reservoirs permeability were obtained. In the microporous membrane filtration experiments, the polymer DQ3500 with the molecular weight of 3.57 × 107 matched the 0.7 μm microporous membrane well. Moreover, three polymer samples including DQ2500 (molecular weight 2.42 × 107), complex polymer BCF (molecular weight 2.42 × 107) and complex polymer ABCF (molecular weight 2.14 × 107) matched the 0.6-0.7 μm microporous membrane well. No retained aggregation was observed on the microporous membranes for all examined polymer samples. Both resistance coefficient (Fr) and residual resistance coefficient (Frr) were measured with five core polymer flooding experiments. Polymer solution including DQ3500 and DQ2500 with the concentration of 1000 mg / L were injected into the artificial cement conglomerate cores with permeability of 121 × 10-3-1000 × 10-3 μm2. The values of Fr and Frr increased with the increasing of polymer molecular weight and decreased with the increasing of core permeability. The average polymer coil hydrodynamic radius (Rh) was measured by the DLS method. The Rh ranged from 266.0 nm to 394.5 nm for the polymers with molecular weight from 2.14 × 107 to 3.57 × 107. Accordingly, the conglomerate reservoir with water permeability more than 55.4 × 10-3 μm2 could not been blocked by those polymers with molecular weight less than 3.57 × 107.
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Reliable Fracture Characterisation and Value Addition through Special Core Reorientation: Kuwait Case Study
Reliable fracture characterization is essential for efficient field development of tight carbonate reservoirs. A comprehensive campaign of core based fracture analysis was carried out on more than 7,000ft of deep tight carbonate (over 14500ft TVD and 3pu avg. porosity and 0.1 mD avg. perm) cores of Kuwait, spread over a number of wells covering a large area of over 1000sq km. The aim of the study was to provide inputs for a detailed structural analysis of the area, with the help of reorientation of cores focusing on the geometrical and structural characteristics of each well. The reorientation procedure used a special core Goniometry process, which permits a totally hands-free 3D digitization of all planar and linear features. Reorientation of the cores is established using either the deviation data from the wells or through comparison with image log data. In addition to the detailed integrated description of type, size, aperture and filling of fractures, a porosity/permeability model was generated after calculation of fracture frequency. By calculating the orientation and value of the permeability vectors, an indication of optimum direction of drilling was established for each well/area. The natural fracture network obtained with open, partially-open and cemented fractures, together with induced stress-release fractures analysis, contributed to a better understanding of tectonic history and present-day stress in the studied area. A field synthesis map highlighted the main direction of all types of fractures and an actual stress map was worked out by compiling all directions of the maximum horizontal stress observed in the wells and oriented by the petal and centreline induced fractures. The integration of the results with analyses of image log data, well log correlation data and seismic data provided critical information about the reservoir properties.
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Best Practices and Application of Integrated Fit for Purpose Technologies to Revitalise High Water Cut Mature Fields—A Case History from Offshore South China
Huizhou oil field, located offshore south China, has been in production for over 20 years. Most of the primary oil was produced from 1991 to 1996 by vertical wells and commingled production. Horizontal geometric drilling was first introduced in 1997. However, as the field became more mature, the rate of success could not be sustained, and a rapid production decline began in 2000. By 2006, the field average water cut reached 90%. A reservoir surveillance program was conducted to evaluate remaining reserves, delineate current oil water contacts, and update geologic and reservoir models. This work revealed that remaining reserves in the high-permeability reservoir accumulated in attic locations, while the reserves of low-permeability reservoirs remained unproduced despite years of commingled production with the high-permeability reservoirs. A new horizontal drilling program was initiated in 2007 to target the 3 m to 5 m thin attic oil column of high-permeability reservoirs overlying strong aquifers. The 1 m to 3 m thin and low-permeability interbedded shale reservoirs were also targeted. Because the reservoir targets are much thinner compared to original conditions, the standoff between lateral and oil water contact is very sensitive to well performance and reserve recovery. Precise landing and lateral placement of horizontal wells and the use of inflow control devices for completion, have become critical to the success of this campaign. The results have shown 39% higher production compared to the set targets, up to 15% improvement in reserves recovery, and 14% reduction in annual field production decline rate. Based on project results, best practices in finding and revitalizing remaining oil in mature fields and complex reservoirs were developed. Project success was also aided by applications of fit-for-purpose technologies, including advance multifunction formation evaluation and azimuthal logging-while-drilling, well placement, and inflow control devices, as an integrated solution.
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A Type Curve for Carbonates Rock Typing
Authors A. S. Wibowo and P. PermadiRock typing for heterogeneous carbonates is still a standing problem. The present work was directed to investigating the relationship between microscopic geological characteristics of carbonates and architecture of the pore systems in the effort to develop a better method for carbonates rock typing. Eight carbonate reservoirs with complete core analysis data of 1,838 core plugs were used in this work. Six carbonate data sets were utilized in developing the method and the rest two were used for verification. The well known Kozeny’s equation was employed to provide the relationship between pore geometry and the structure. It can be shown that these pore attributes contain only permeability and porosity. A comprehensive analysis was then carried out by plotting pore geometry against pore structure on log-log graphs (PGS cross-plot) and identifying microscopic geological features of every core plug employed. Results for each carbonate data set show that the data points divides into six to thirteen clusters, each cluster has its own similarity in the microscopic geological features, the fitting line drawn on each cluster has very high correlation coefficient, the space between two closest fitting lines is all practically the same, and interestingly all the fitting lines tend to converge to a single point. A mathematical analysis done confirms the existence of this point, leading to the construction of a type curve. The rest two carbonate data sets perfectly verify this type curve. This work differs from the previous ones in that the present work honors both geological and engineering aspects equally and reveals that certain diagenetic processes have produced certain pore architecture as exhibited on the PGS plot. This paper overall provides a better understanding about rock type definition, a tool to identify the effects of diagenetic processes on rock properties, and a type curve for easy rock typing.
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Successful Implementation of Zirconate Borate Based Dual Crosslinked Gel and Continuous Mixing System During Proppant Fracturing Treatment in a Complex High Temperature and High Pressure Sandstone Gas Reservoir in Saudi Arabia that Exceeded the Well Objective
The success in a proppant fracture treatment depends on achieved effective fracture half-length and vertical proppant distribution. The desired fracture geometry can be challenging to achieve in deep and heterogeneous sandstone reservoirs in Saudi Arabia where temperature (up to 350 °F) and pressure are very high. Conventional borate based cross-linked polymer guar gel as a fracturing fluid — for high pressure high temperature (HPHT) reservoir in KSA — is outside of the optimum envelope as far as required rheology is concerned and exhibits extreme sensitivity to brine quality at bottom hole static temperature (BHST). A new fracturing fluid consisting of Carboxymethyl-Hydroxypropyl Guar (CMHPG) crosslinked with dual-crosslinker (Borate and Zirconate) has been found to be a more suitable fluid — than only borate based crosslinked fluid — for HPHT gas wells. This new fracturing fluid provides stable rheology under bottom-hole conditions, is compatible with reservoir fluids, and has excellent proppant-suspending and leak-off properties, while providing improved retained proppant permeability. Most sandstone gas completed with cased-hole or Multi-Stage-Frac completions in Saudi Arabia require large size proppant fracture treatments. The base potassium chloride (KCl) brine and linear gel are batch-mixed prior to fracturing treatment. This batch mixing process is time consuming and takes up to 3 days per stage fracture treatment. A significant increase in operational efficiency and fracturing fluid quality was observed when all fracturing additives, including: solid polymer and liquid Organic Clay Stabilizer (OCS), a KCl substitute; were used on-the-fly in a HPHT gas well during proppant fracturing treatment, utilizing an advanced continuous mixing system. The advanced continuous mixer was a pumping and blending system that provided linear gel to the blender. The system continuously metered and simultaneously mixed dry polymer powder to produce a gel at desired concentration that was completely free from oil-based material. A total of eight additives were added on-the-fly, utilizing solids and liquid additive system mounted on advanced continuous mixing and blender units. This paper provides details on lab testing, treatment design, field implementation, and treatment evaluation of a complex HPHT gas well in Saudi Arabia using the novel fracturing fluid system and state-of-art Continuous Mixing System.
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The World's First Real Time Logging with Tractor in an Extended Reach Horizontal Well with Proof of True Stimulation
Authors J.O. Arukhe, S. Ghamdi, M. Dhufairi, L. Duthie and K. OmairenAlthough engineers have employed tractor interventions relatively extensively in well stimulation of extended reach wells in this field, an outstanding challenge in the field and even in the industry has been to conduct real-time acquisition of inflow or production profiles and to evaluate treatment effectiveness in extended reach open hole horizontal wells. This challenge was overcome from real-time electrical to optical (EtO) water injection profile measurements simultaneously with running a tractor. The motorhead assembly (MHA) of coiled tubing (CT) was successfully wired through a tractor to allow the world’s first successful real-time acquisition of an inflow profile in an extended reach open hole horizontal power water injector in one of the current largest field development projects in the world. The well, located on one of two finger islands, was completed to a total depth of nearly 30,000 ft (over 9.10 km) MD; making it the deepest open hole section logged in the field development outside the normal reach of tapered CT for well intervention. The intervention on the well was successfully carried out through the application of a 2-in. tapered CT and well tractor. The well’s treatment involved 3,850 barrels of emulsified acid recipe in 14 stages. A comparison of the pre- and poststimulation injectivity indices showed an eightfold injectivity index improvement from 53 bpd/psi to 400 bpd/psi. The resulting marked improvement in injectivity from acid stimulation also revealed the benefit of informed decisions from the real-time fiber optic distributed temperature sensing (DTS) in fluid placement. Effective stimulation was critical for increasing injectivity and creating conductive flow paths between borehole and the reservoir. Relatively good transmissibility between the injectors and producers during the commencement of a field-wide waterflood was crucial because of a relatively high viscosity tar layer between the overlaying oil column and aquifer. This tar layer was a challenge for assuring adequate aquifer support to the producers because of their partial sealing nature. For reasons of optimizing sweep and recovery, the placement of water injection wells and requirements was focused around the flanks of the structure. The ability to employ real-time information to effectively stimulate and log inflow profiles in extended reach wells has provided assurance that stimulation can serve as a technical and an economic solution for addressing the relatively high skin damage post drilling and completion. Other practical applications of the success outcome from the real-time acquisition of inflow profiles includes the reduction in the transmissibility uncertainty between the producers and injectors in the field development partly because of the availability of better quality data for reservoir simulation or characterization purposes.
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Unlocking the Potential of Complex Marginal Reservoir in Highly Mature Oil Field, XiJiang 24 South China Sea
An oil & gas operator in XiJiang block offshore South China has shifted the development of highly mature oil fields that have been producing for 17 years toward the remaining undeveloped marginal reservoirs using a horizontal well drilling program. The main targets of the new development campaign are the remaining thin oil column reserve in attic locations of the reservoirs as well as the unproduced thin laminated reservoirs in the area. Upon understanding the uncertainties and challenges associated with drilling horizontal wells in these complex reservoirs, an innovative drilling approach was initiated for accurate horizontal placement in thin sands, channel sands, and thin oil column reservoirs with strong bottom-water. The approach includes the integration of an advance multifunction formation evaluation Logging-While-Drilling (LWD) tool that provides real-time formation evaluation and structural interpretation along with a bed boundary mapper LWD tool with the ability to map multiple key boundaries that are the prerequisite parameters that must be identified during the execution stage and which include the water contact and top and bottom of the reservoir structure simultaneously in distance. Outstanding outcomes have been observed by implementing this new approach in the complex target reservoirs. The approach was applied to multiple challenging wells, each of which has produced from 2,000 to 6,000 BOPD with very low water cut, far exceeding the set production goals of 1,500 to 2,000 BOPD. These are very promising development economics in the oil fields that have 90% to 95% water cut on average.The successful implementation of the new development strategy in highly mature oil fields will lead to sustained and extended production, increasing the ultimate recovery and well economics. The approach provides an example of using integrated technology solutions to overcome the challenges in complex target reservoirs.
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Application of Walkaway VSP for Improving Seismic Imaging of Fractured-cavernous Carbonate Reservoirs
Authors Yimou Liu, Xianghao Liang, Yi Zhou, Shiyong Liu, Xiaofeng Wang and Yanpeng LiOrdovician carbonate rocks are widely distributed in Tarim basin, western China, and they are the important yet very difficult targets in the oil and gas exploration and development. The carbonate reservoirs are ultra-deeply buried and their storage spaces are mainly secondary dissolved caves, holes and fractures of various sizes. The main challenges for seismic imaging are that the target formations are usually in very low signal-to-noise ratio due to the seismic attenuation, and the reservoir media are strong heterogeneous (caused by caves and holes) and having varying degrees of anisotropy (caused by fractures). Conventional processing techniques fail to image and identify the fractured-cavernous reservoirs accurately. In order to better image and identify the reservoirs, an 8-azimuth walkaway VSP (with a maximum offset of 6600m from the wellhead and covers the 510m-6470m depth interval with receiver spacing 10m) was carried out to estimate the true amplitude recovery (TAR) factor, Q factor and VTI anisotropic parameters, and then proper energy compensation approaches and VTI anisotropic migration algorithms are introduced in the seismic processing flow. The results show remarkable improvement in seismic imaging, and the depth errors of the geological targets are reduced considerably.
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Case Study: Productivity Evaluation of Ultralow‑Permeability Clastic Oil Reservoir Drilled at High Overbalance with Water Based Mud
Authors Shi HeShen and Xian ChengGangUltralow-permeability (1.0- to 10- md) oil reservoirs are becoming primary targets offshore China. Reliable productivity evaluation is needed for such reservoirs, which have significant technical challenges and a narrow economical margin. Evaluation of wells drilled at high overbalance with water-based mud (WBM) presents several key challenges: severe near-wellbore formation damage, lack of porosity-permeability relationships because of the complex pore structures, large-scale permeability effects from pronounced heterogeneities, and big discrepancies among the permeability sources for which analysis is complicated by different measurement environments and interpretation methods. Parameter discrepancy creates significant bias for determining cut-offs and optimizing completion and stimulation strategies. More significantly, defining producible pay and consequently how it will produce are greatly complicated by capillary pressure and relative permeability conditions. Very different pictures may be drawn if these challenges are not addressed systematically. A comprehensive case study provided lessons learned for the productivity evaluation of an ultralow-permeability clastic oil reservoir drilled at high overbalance with WBM. An integrated approach was conducted to overcome challenges by using all available data through extensive data acquisition. Flow-based rock typing (FBRT) with a neural network used pore structure, capillary pressure, and relative permeability as key inputs or control parameters in addition to the routine parameters in conventional rock-typing methods. Different permeability sources with different scales were systematically integrated and up-scaled into a numerical model based on classified FBRTs and validated by history matching of dynamical tests. Pore structure delineation is identified as the key input for reliable productivity evaluation. FBRT presents an attractive solution if measurements of pore structure, capillary pressure, and relative permeability and dynamical data are carefully used. Optimizing productivity must start with minimizing formation damage and progress through optimizing completion and stimulation.
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Development Optimization of a Marginal Oil Field in Bohai Bay, China - Integrated Solutions to Overcome Challenges in Offshore Horizontal Well Construction
Authors Chaomin Nie, Yongsheng Zhao, Lv Tan, Yong Jia, Gang Zhai, Parlindungan Monris Halomoan, Xu Chong Hui, Wang Yong, Wang Fei and Dong JianyiA total of nine horizontal wells including one injector well were drilled to cover the small, 9 km2, oil-bearing area of a marginal oil field that is isolated by secondary faults and stratigraphic depositional borders in Bohai Bay, China. A pilot study showed that the reservoirs are distributary channel sands of a shallow water deltaic depositional system. Seismic inversion indicated that the sand properties and connectivity vary dramatically across the field. A multiple-aquifer system was apparent, and the gas/oil contact (GOC) and oil/water contact (OWC) levels were unknown. Furthermore, the only well control was from three vertical exploration wells and two directional offset wells. An advance distance-to-boundary well placement technique using azimuthal deep directional electromagnetic loggingwhile-drilling (LWD) technology was applied to overcome these challenges and to enhance reservoir understanding. A multifunction LWD formation evaluation tool was deployed to evaluate fluid properties where the top gas might occur. In addition, a rotary steerable drilling system (RSS) was assembled to achieve drilling efficiency and smooth trajectory control. One injector well and eight producer horizontal wells were precisely placed in optimum position for injection and drainage with a 100% success rate; one producer horizontal well was retracted while another producer well was added based on finding definite GOC and OWC levels. Increasing the drilling penetration rate and avoiding adjustments following reservoir exits led to a 60% improvement in drilling efficiency, which is equivalent to a cost savings of USD 32 million. Production from these horizontal wells surpasses the set production target by 30%, with extremely low water cut. The integrated LWD, well placement, and RSS solution optimized the marginal oil field into a much more economic development oil field.
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Quantitative Estimation Of Gas Saturation By Frequency Dependent AVO: Numerical, Physical Modelling And Field Studies
Authors Xiang-Yang Li, Xiaoyang Wu and Mark ChapmanIt is well known that seismic amplitudes contain important information which can be related to fluid saturation. Most interpretation is based on Gassmann’s theory and studies of amplitude variations with offset (AVO) with the Zoeppritz equations. However, this traditional AVO technique is often unable to make quantitative estimation of the gas saturation, hence unable to distinguish between commercial and non-commercial gas deposits. Recent attention has focussed on if the frequency response of reflections can also be used to reveal fluid information through the application of frequency-dependent AVO (FAVO), although many of these studies are based on empirical relationships and are lack of a thorough understanding of the underline mechanism and rock physics principles. In this study, we extend the “squirt-flow” model to include the effect of gas saturation on seismic attenuation and dispersion. Combining with Wood’s formula, the FAVO response can be calculated as a function of porosity and gas saturation. Therefore a model-based inversion scheme can be established by matching the calculated FAVO response to the observed ones for quantitatively estimating the gas saturation. There are three technical contributions in this approach: 1) a theoretical frame work for modelling the FAVO response and the effects of gas saturation on seismic attenuation and dispersion; 2) an efficient spectral decomposition algorithm for extracting the FAVO response from real data; 3) an optimization work flow for estimating the gas saturation. In our examples, the numerical modelling is able to predict the FAVO response to changing gas saturation which is seen in the physical modelling data, and the 3D P-wave field seismic data. Consequently we argue that with a careful model-based approach, it is possible to invert the FAVO response in terms of gas saturation. This may have important implications in the exploration of tight and unconventional gas resources.
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Successful Development of Thin Zones: Challenges and Strategies
Authors Ali Al-Julaih and Obai TaibahThin reservoirs that are only a few feet in thickness present a clear challenge to development specially when coupled with fractures, lateral heterogeneities, and structural uncertainties. This paper discusses the challenges associated with the development of a thin zone located at the top of a carbonate reservoir as well as the strategies implemented to overcome these challenges and develop the zone successfully. Due to the lower rock quality when compared to the underlying zones and extreme thinning, this zone could not be produced through the conventional vertical wells historically. Through the strategic monitoring program implemented in the field, an opportunity to place direct production from this zone has been identified specially in the mature areas of the field where the lower zones are fully swept after decades of continuous production whereas a thin zone at the top of the reservoir is unswept. Capitalizing on this opportunity, a strategic development plan has been initiated. This plan calls for placing horizontal laterals in this zone utilizing recently developed fit-for-purpose well placement and completion technologies. To successfully develop this challenging zone, several strategies have been implemented. First of these was strategic well planning where a systematic methodology was implemented to evaluate and develop this zone. The most promising target areas were located through comprehensive evaluation of the area, with detailed geological modeling. Secondly, advanced geosteering with a rotary steerable system (RSS) has been utilized to efficiently place laterals in the upper lobe of the targeted zone. Advanced completions, using inflow control devices (ICDs), were utilized as a fit-for-purpose to mitigate the counter effect of fractures and/or pressure differences across the horizontal section. The development program has been very successful in yielding significant production gains.
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Non-Hyperbolic Moveout Multi-Parameter Anisotropic Tomography
Authors J. Panizzardi, N. Bienati and E. GentileApplication of anisotropy has proved to be mandatory for the improvement of imaging quality, at the point that nowadays the introduction of TTI anisotropy has become a standard for PSDM projects. These advancements pose new challenges to migration velocity analysis, and the time domain approaches commonly used for the estimation of anisotropic velocity parameters are no longer enough to satisfy imaging accuracy requirements. A depth-domain estimation technique is proposed, which is completely based on PSDM and on the classic CIG (Common Image Gather) flattening principle. One of the key aspects is the use of a robust automatic non-hyperbolic moveout picking algorithm, which is applied on the depth migrated CIGs and provides the correct description of the complete residual moveout: this allows the joint tomographic inversion of two anisotropic velocity volumes, which are able to properly account for the non-hyperbolic residual moveout behavior at both short and long offsets. The method has general validity and it can be applied to any imaging project; it is also particularly stable when applied to multi-azimuth acquisitions. This approach can obtain a good anisotropic focusing velocity if the data contains sufficiently large offsets, although still one or more wells are needed to constrain vertical velocity.
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Sour Gas Amine Filtration Enhancement
By Asif KhanSaudi Aramco Gas Operations can process over 8 BSCFD of gas. Diglycolamine (DGA) is the most widely used Amine in gas treatment facilities. Similar to other types of amines such as monoethanolamine (MEA), diethanolamine (DEA) and methyl diethanolamine (MDEA), the performance of DGA is mainly reduced by accumulation of contaminants, e.g. suspended solids, hydrocarbon liquids and degradation products. Foaming, solvent loss, fouling and other operational problems are associated with DGA contaminants in high-pressure (HP) DGA systems. Low pressure systems generally have more stable performance with less operational issues. These issues are generally managed by anti-foam injection, fresh solvent addition and installation of mechanical filters. The gas treatment system is equipped with inlet gas filtration and amine filtration to reduce the contamination level in DGA, e.g., suspended solids, pipe corrosion due to aging and hydrocarbons. Slug catchers remove the bulk of liquid in the gas. Three phase separators with coalescing element remove liquid aerosols and solid particulates. DGA filtration consists of a pre-coat filter (1 micron rating) and a mechanical filter (5 micron rating) installed on a slip stream. The pre-coat filter consists of diatomaceous earth (diatomite or kieselguhr) coating material bonded to a mechanical screen or leaf. The filtration media is chemically inert and contain a silica skeleton. A precoat filter removes suspended solids, contaminants and other particulate matter; to build a pre-coat primary filter medium layer to be deposited on the basic screen. The correct cake buildup is essential for optimum filtration results. Sometimes pre-coat filter performance is not up to a satisfactory level due to the quality of cake build up. Gas plants are putting extra efforts to maintain gas treatment units to control amine quality.
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Scale Management in Mature Gas Field: Case Study of Peciko
Authors F.A. Bajammal, H.M. Biyanni, A.P. Riksa, H.M. Poitrenaud and A. MahardhiniPeciko is one of the giant gas fields located in the Mahakam area, Indonesia, operated by Total E&P Indonesie. Since start up in December 1999, until May 2012, the average wellhead pressure and temperature of its wells have decreased from 150 barg to 20 barg and from 95 °C to 60 °C, respectively, while the average water/gas ratio (WGR) has increased from approximately 2.5 to 20.5 bbl/MMscf. These dramatic shifts of production parameter and borehole environment are believed to be the main factor of the increasing rate of scale deposition in significant number of its wells in the last few years. The nature of the scale encountered is mainly calcium carbonate and iron carbonate. Reviews have been carried to better understand the phenomena of scale formation in the field and to formulate the optimum solutions in overcoming it. Guidelines have been established to facilitate early detection or prediction of scaling, which includes routine water analysis, periodic check of tubing clearance, and running multifinger caliper in the well. Numerous attempts of removing the scale have been tried, with mechanical and/or chemical techniques, from light intervention using slick line unit, until semi-heavy intervention with coiled tubing unit (CTU). Several successful results have been observed, to some extent. Calcium carbonate scale showed to be relatively easy to remove, but the presence of iron carbonate imposes more challenge and complication. The milling operation, in particular, has been improved to minimize the negative effect of liquid circulation in sensitive wells, i.e. evolving from CTU milling using brine, to CTU milling using nitrified base oil, to electric line milling without liquid circulation. The guidelines, lessons learned, and the foreseen solutions are considered as the key elements of scale management in the field, and will be described further in the paper.
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The Spectrum of Fine-Grained Reservoirs from 'Shale Gas' to 'Shale Oil'/ Tight Liquids: Essential Attributes, Key Controls, Practical Characterization
Authors K. M. Bohacs, Q. R. Passey, M. Rudnicki, W. L. Esch and O. R. LazarA spectrum of combinations of rock and hydrocarbon properties in fine-grained rocks can result in significant production, effectively spanning ‘conventional’ tight oil to fractured ‘shale’ gas reservoirs, in four main families based on dominant porosity-permeability system and stratal relations (i.e., ‘Conventional’ tight, Hybrid/Interbedded, Porous ‘shale’, Fractured ‘shale’). Fine-grained reservoir types comprise ‘shale-oil’ reservoirs at lower thermal maturities and pressure-temperature (P-T) conditions to ‘shale-gas’ reservoirs at higher maturities and P-T conditions. These fine-grained reservoirs can contain a variety of pore types: inter-granular, intra-granular, fracture, intra-kerogen, and intra-pyrobitumen/char -- the last two ‘organic-hosted’ types are more obvious at higher maturities. ‘Shale-oil’ reservoirs share many attributes with ‘shale-gas’ reservoirs, but have some distinct differences. The key additional dimension is the properties of the hydrocarbon fluids: Over geological time, fluid density and phase influence fluid saturation in the matrix, and in the short term, viscosity and phase affect flow and production rates. Hence, two main classes of attributes affect ultimate ‘shale’ reservoir performance: rock properties (mainly permeability) and fluid properties (mainly viscosity) that are influenced by the full geological history of the reservoir. Overall reservoir permeability includes both matrix and fracture characteristics: Matrix permeability is a function of original depositional composition, texture, bedding, and stratal stacking plus burial history (thermal stress, diagenesis). Fracture permeability is a function of the same controls as matrix permeability along with structural history (mechanical stress). Fluid properties (viscosity, density) are also controlled by original depositional properties (which determine kerogen type) and burial/uplift history, along with present-day reservoir pressure and temperature. The higher thermal maturities of ‘shale-gas’ reservoirs result in contrasts with ‘shale-oil’ reservoirs: they tend to have less smectite due to illitization, but more obvious porosity associated with kerogen and bitumen. These factors modify the porosity-permeability system and well-log responses. Appreciation of the similarities and differences between ‘shale-gas’ and ‘shale-oil’ enables more efficient and effective exploitation of the full range of resource types.
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Fill Cleanout Operations in Offshore Saudi Arabian Fields: Case Histories toward Improving Economics and Operational Logistics
Authors K. S. Yateem, H. B. Qahtani, S. S. Saeed, Saudi Aramco, J. Li and B. AitkenCoiled tubing (CT) fill cleanouts have been in existence for over four decades and today account for approximately 30% of the services performed. Both CT and conventional jointed pipe offer a forward or reverse circulation mode to remove solids; however, using conventional water-based fluids, a sand cleanout method may apply excess hydrostatic pressure to the formation, resulting in some lost circulation to a sub-hydrostatic reservoir. Nitrogen (N2) can be used to reduce hydrostatics, but this requires a very precise job design and execution. Moreover, N2 use can have adverse logistical and economic implications – large amounts of N2 may be needed, especially in larger diameter wellbores and in horizontal wells. Several cleanout methods have been utilized in the past, employing a variety of different approaches. CT historically has incorporated limited circulation rates, exotic/costly fluids and reversing circulation to remove solids. The use of CT to remove sand from wellbores was one of its earliest applications and continues to be an important service today. This paper will discuss cost-effective solutions in Saudi Arabia, highlighting field cases and job optimization. The selection of the most appropriate sand cleanout method has to be based on both logistical and technical issues. This paper shows how to select the most cost-effective fills cleanout method for these wells. A few field cases are discussed to demonstrate the proper operational procedure, challenges and lessons learned. The combination of how to utilize the sophisticated solids transport software, downhole switchable nozzle, and proper operational procedure with the frequent evaluation of downhole conditions on site is essential to insure the fills cleanout is executed 100% successfully.
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The Adaptability Research of Steam Flooding Assisted by Nitrogen Foam in Henan Oilfield
More LessWith the further study on foaming agent performance, steam flooding assisted by nitrogen foam has been applied more widely. But the flexibility of this technology in heterogeneous shallow layer heavy oil reservoir has not been fully researched. Through introducing a new dimensionless parameter — foam comprehensive evaluation index (FCEI), we use physical simulation to evaluate foaming agents. Then we make five sand filling tubes modeling permeability contrast in the light of Henan heterogeneous shallow layer heavy oil reservoir. Based on two kinds of foam-injected methods (steam following or not) impact analyses, the applicability of foam to multi-permeability contrast is further discussed. Furthermore, we use numerical simulation to optimize parameters including foam slug size, nitrogen steam ratio, foam injection interval and productioninjection ratio, which applied to this type of reservoir. The obtained results show that through foaming coefficient and decay coefficient, FCEI can unify the criteria of foam screening by taking foam volume and half-life into consideration. On even ground, compared with cold foam flooding, the oil production of unit foaming agent of hot foam flooding stays 1.24 % higher. There exists none negative correlation between foam’s contributions to each layer’s flooding efficiency and permeability. Two methods both indicate that the middle permeability layer, of which the producing degree is similar with lower ones, has great exploitation potential. When injected with cold foam, the start-up pressure of heterogeneous formations increases linearly along with the increase of permeability grade, but for hot foam, this value increases in function of power. And to higher permeability contrast layers, hot foam is better. Finally, under hot foam slug injection condition, the optimum foam slug size is 0.02PV, the optimum nitrogen steam ratio is 20:1, the optimum foam injection interval is 90 days and the best production injection ratio is 1.32:1. Based on the study, this technology has been applied for selected field sites in 2011, and preliminary results have been achieved. The results demonstrate that this research can play an important guiding role in applying steam flooding assisted by nitrogen foam to heterogeneous shallow layer heavy oil reservoir.
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Seismic Attributes and Advanced Computer Algorithm Method to Predict Formation Pore Pressure: Paleozoic Sediments of Northwest Saudi Arabia
Authors Abdoulshakour Nour and Nasher AlBinHassanOil and gas exploration professionals have long recognized the importance of predicting pore pressure before drilling wells. Pre-drill pore pressure estimation not only helps with drilling wells safely but also aids in the determination of formation fluids migration and seal integrity. With respect to hydrocarbon reservoirs, the appropriate drilling mud weight is directly related to the estimated pore pressure in the formation. If the mud weight is lower than the formation pressure, a blowout may occur and, conversely, if it is higher than the formation pressure, the formation may suffer irreparable damage due to the invasion of drilling fluids into the formation. A simple definition of pore pressure is the pressure of the pore space fluids in excess of the hydrostatic pressure. The cause of abnormal pore pressure includes quick burial of unconsolidated sediments before dewatering, hydrocarbon formation in the pore space of rocks, mineralization such as smectite-illite osmosis, tectonic movement of sediments and other geological processes that result in overpressure. Geoscientists and engineers have used various techniques to predict abnormally high formation pore pressure from seismic data. These techniques primarily employ the empirical relationship between seismic velocities and formation density. Consequently, many investigators have shown the sensitivity of seismic velocities to other factors such as lithology, gas and pore fluid content, which reduces the reliability of purely velocity-based methods in predicting abnormally high formation pressure (Young and Lepley, 2005). In this study we will focus on using an advanced pattern recognition computer algorithm, called Support Vector Machine (SVM) and attribute data from seismic and wells to the prediction of formation pore pressure in the lower Paleozoic Qalibah formation of northwest Saudi Arabia.
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The Production Enhancement of NGL and Reduction of Pipeline Liquid Condensate Flaring with Successful Implementation of Triethylene Glycol Dehydration Unit
More LessTo meet the future sustainability requirement(1,2), major energy suppliers in the world have been pursuing the highest standards of environmental policy to contribute the conservation of natural resources through operation excellence and energy optimization. Abqaiq Plant is the largest oil stabilization plant in the world. A small improvement in separation process could lead to significant energy saving and reduction of CO2 release for its large scale. The crude oil processing units at Abqaiq Plant have two major functions. First, crude feeds from oil field are stripped with steam which increases the moisture content of offgas from the oil stabilization column. Second, the low pressure offgas is pressurized to 450 psig for separation of NGL products. The final NGL product is transferred to the downstream refinery for further processing and the offgas from the NGL facility is transferred to the downstream gas plants for sulfur removal. For years, gas pipelines have been suffering from back pressure caused by liquid condensate accumulation in the pipeline. To reduce the back pressure, enhancement of NGL recovery is required but the challenge is to lower the deethanizer operation temperature without hydrate formation. As a part of the global downstream pipeline and plant optimization program, Saudi Aramco has invested $65MM capital expense for triethylene glycol (TEG) dehydration unit(3,4,5) at the world largest oil stabilization facility to reduce the frequency of pipeline scraping. The success of this project would eliminate 2 million pipeline scraping cost and 40 million of liquid condensate reprocessing and liquid flaring every year. The liquid condensate flaring has imposed a serious adverse environmental impacts and risk to operator exposure to hydrogen sulfide. Commissioning of the TEG dehydration unit was initially unsuccessful for the issue of plant piping network back pressure. To achieve the full benefits of the newly implemented TEG unit, the Abqaiq Plant operation engineering unit has utilized the advanced real time optimization (RTO) model to identify the root causes of failure. Process studies including the feasibility of steady state normal operating conditions and the piping flow estimations were completed by RTO data reconciliation model. Further offline studies for pressure drop analyses on piping networks were completed with additional pipe diameters and roughness data. The location of back pressure was identified by the advanced engineering tool. A new operation transition plan was developed to avoid pipeline back pressure. As a result of this new approach, the NGL production rate was successfully increased by 15 MBD which accounted for $200MM of annual revenue. The commissioning team has also demonstrated a successful story from collaboration of interdisciplined team within the company.
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Multi-Azimuth Seismic Data Imaging in the Presence of Orthorhombic Anisotropy
Authors Yi Xie, Sergey Birdus, James Sun and Carl Notforseffects are important by themselves and can be a target of special studies. The presence of orthorhombic anisotropy poses challenges in wide azimuth imaging which has been rapidly developed for better illumination, better imaging, and better multiple elimination. Analysis of multi-azimuth (MAZ) data often reveals noticeable fluctuations in moveout between different acquisition directions, preventing constructive summation of MAZ images due to the azimuthal dependency nature of wave propagation in orthorhombic medium. On the other hand, the coexisting VTI effects of orthorhombic anisotropy can also cause well misties and higher order moveout. Orthorhombic anisotropy can take into account the co-existing HTI/VTI effects. We have developed an approach for imaging in the presence of orthorhombic anisotropy, including orthorhombic velocity analysis and orthorhombic migration. Following Tsvankin’s work, we put forward a ray tracing approach suitable for both weak and strong anisotropy which applies to both Kirchhoff and Beam PSDM. Aimed at the challenge in orthorhombic anisotropy model building, we have developed a practical workflow which combines the co-existing HTI/VTI anisotropy estimated through multi-azimuth tomography to form the orthorhombic model. In this paper, we first describe our approach for imaging in the presence of orthorhombic anisotropy, including the newly developed orthorhombic ray tracing method and the newly developed practical method for orthorhombic anisotropy model building. We then demonstrate with both synthetic and real data from offshore Australia that our approach can successfully take into account the co-existing HTI/VTI effects, reduce the structural discrepancies between seismic images built for different azimuths, hence produce constructive summation of MAZ dataset, resolve well mistie to match with geology, and deliver a step-change in the final seismic image quality.
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Use of High Resolution Sequence Stratigraphy in Building: 3D Reservoir Geological Model - A Case Study from Kuwait
A number of structures are producing hydrocarbons in commercial quantity from the carbonate reservoirs of Middle Marrat Formation in the Northern part of the State of Kuwait. Seismic resolution of these deep carbonate reservoirs of Toarcian age is strongly affected by multiples from overlying Gotnia-Hith salt-anhydrite layers impacting true understanding of the internal depositional architecture from seismic data making it difficult to make realistic geological models. An extensive coring campaign adopted over a period of time for improving the understanding of depositional settings and diagenetic processes in these reservoirs and subsequent studies helped in developing a correlation based on sequence stratigraphic principles. In the Middle Marrat Formation seven cycles with sequence boundaries and maximum flooding surfaces were identified. The best reservoir facies are located in High Stand Tract, corresponding to the progradation of the carbonate platform in the form of clinoforms sloping towards the basin. 3D geological model was built with a framework base on this correlation capturing the higher order sequences with the prograding and aggrading carbonate shelf. Sedimentary facies were identified from electrologs with complete calibration from core description and ECS calibrated ELAN processing results. Gross depositional environment maps were prepared to guide the distribution of primary sedimentary facies within the model for different depositional environments like Slope/Basin, Outer Shelf, Inner Shelf, Shoreface, Barrier/ Shoal, Backbarrier/ Backshore, Lagoon, Tidal Flat, and Sabkha using templates developed for different sequence boundaries. These carbonates are characterized by seepage reflux dolomitization process and burrows giving rise to enhanced porosity and higher productive layers. This diagenetic imprint was modeled on the primary facies in shoreface and inner shelf areas. This facies model was used to distribute other reservoir properties like porosity, permeability and water saturation using different techniques. The developed model was further calibrated with isotope geochemistry studies and was also validated from comparison with exposed and well studied geological analogue examples. This model showed better predictive capability for wells drilled subsequently. In this carbonate reservoir, a sequence stratigraphic framework holds the key for distributing the reservoir facies within a 3D geological model in a realistic manner giving better predictability of reservoir properties and facies thereby reducing the field development uncertainty.
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Application of Reservoir Navigation with Boundaries Detecting Technologies in Lufeng Oilfield, South China Sea
Authors Hao Yiling, Xiong Shuquan, Wu Yiming, Fang Yongjun and Li ChuyinReservoir Navigation with Boundaries Detecting Technologies, Baker Hughes AziTrak™ azimuthal navigation can achieve maximum standoff to oil/water Contact and minimum standoff to shale roof, increase exposure to reserves and identify future opportunities. CNOOC, one of China’s major operators recently used this services drilled 7 wells with 3570 m lateral section in the Early Miocene Zhujiang sandstone formation while maintaining a challenging distance of 0.8 m from the roof of the formation and safe standoff above bottom/boundary water. "The ability to drill accurately within the zone was impressive, and the ability to also drill it fast was remarkable, with exact wellbore placement, you can extract more value from mature field" said the client’s management representative. In the demonstration effect of this field, more and more fields of CNOOC are taking the Reservoir Navigation with Boundaries Detecting Technologies to facilitate simplified reservoir navigation decisions for increasing efficiency, saving rig time with early oil-water contact-zone detection, driving maximized hydrocarbon recovery through precise wellbore placement. This paper will be focusing on above cases to study. The following figures illustrate some contents of this paper.
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Renovation of Old Well Logs Run in Boreholes Drilled with Oil-Base Mud
More LessThe problem of correcting for oil-base mud filtrate invasion has been resolved using modern well logging technology of tools and interpretation techniques. However, many well logs from old wells remain uncorrected. Old interpretation assumed no oil base mud filtrate invasion. The consequences may vary between unnecessarily perforating a waterbearing zone to even worse by completely by-passing a hydrocarbon formation. Lau et al. (1989) developed a correction for oil-base mud effects on neutron and density logs, however the standard formation evaluation techniques from the Dual Induction Resistivity Log, DIL, relies on knowledge of the resistivity of the invaded zone, Rxo. Since no electrode-type tool can work in oil base mud to measure Rxo, a synthetically derived Rxo from the Electromagnetic Propagation Time (EPT) or the Thermal Neutron Decay time (TDT) logs is used. In the absence of these unconventional EPT or TDT logs, interpretation is performed assuming no oil mud invasion and the deep induction resistivity, RID, is reading the true formation resistivity, Rt. However, it has been proven that oil mud filtrate will invade the formation sometimes to a diameter greater than 120 inches. This invasion will greatly affect Rt masking the hydrocarbon potential of the reservoir to the extent that a water zone may appear as hydrocarbon-bearing. Without proper consideration to the oil-base environment surrounding the logging tools, essential petrophysical parameters such as true formation porosity and resistivity cannot be accurately measured. Techniques and concepts such as crossplotting log versus log Rt or log Rxo, BVW, shale zonation index, fracture partitioning coefficient, etc. may not be all conducted. Evaluation of properties such as Sw, Sxo, Smo, m, n, ma, f, FII, etc. will not be reliable. Consequently, zonation of a heterogeneous reservoir into its hydraulic units cannot be accomplished. In this study, a new practical and cost effective technique is introduced to correctly evaluate formations with deep oil-base mud filtrate invasion of old well logs in the absence of EPT, TDT, logs, i.e. without a prior knowledge of Rxo or Rw. This will allow characterization of old reservoirs drilled with oil-base muds using the available old conventional well logs without the need for running new expensive well logs.
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Evaluation of Inflow Control Devices to Reduce the Water Production in Horizontal Wells of the Orinoco Heavy Oil Belt
Authors I. Y. Vasquez, J. R. Rodriguez and E. A. FernandezThe Orinoco Heavy Oil Belt, located in the southern part of the Eastern Basin of Venezuela, is considered the largest deposit of heavy oil in the world. It covers an area of 14 million acres and is characterized by having crude of low API gravity (from 7 to 10º), high viscosity (from 1,000 to 10,000 cp), high porosities (from 18 to 40%) and permeabilities that can reach 30 darcies. Heterogeneity is present in the Faja, there some areas with active bottom aquifers. On these particular areas an early water breakthrough has been identified in some horizontal wells. A numerical simulation model with representative properties of an area of the Orinoco Heavy Oil Belt was defined to assess if the implementation of inflow control devices (ICDs) could reduce water production in horizontal wells. The numerical model contained a horizontal well where these completions elements were installed. The evaluation was made through a sensitivity analysis in which the configuration of the devices and some rock and fluids properties were changed. Additionally, the effect of the horizontal well length was studied as this parameter is relevant in the design and planning of horizontal wells in the Faja. The results of this investigation indicated that the use of inflow control devices can be an effective technology to delay water breakthrough in areas where there is an active bottom aquifer with a good understanding of the geological properties and reservoir behavior. On other hand, this study showed how the differential increase in the cumulative oil of the wells decreases progressively as the horizontal well length section increases. An economic model was created to compare the different simulation scenarios. This research serves as a basis for determining the feasibility of implementing inflow control devices as a water control technology and to obtain valuable information to designing the horizontal section of the wells.
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Successful Multistage Hydraulic Fracturing in V-Shape Well as a Method for the Development of Coal Bed Methane in China
More LessThere is a rich coal bed methane reserve in the southeast margin of ordos basin. Hydraulic fracturing stimulation is the primary completion method to coal bed methane wellbores for many years in this area. Recently, V-Shape wells, which are complex architecture wells composed of a vertical well and two horizontal wells, are in order to improve recovery of CBM. Two horizontal wells intersect with vertical well in same depth, and the included angle between two well tracks of the plan projection is about 44 degree. Multistage hydraulic fracturing technology was treated two horizontal wells to create fracture network and induce nature fractures. Then, the vertical well was used to drainage to decrease bottom pressure. Based on the geologic parameters, a total of eight stages were placed on two horizontal sections. One had three fractures, the other had five fractures. According to wellbore condition, pump bridge plug technology was used to execute multistage fracturing treatments. During field operation, 7200 m3 active water was mixed with quartz sand (492m3) and pumped down two wells together. The averaged proppant concentration was 14%. Because of included angle, the number of sand changed with stage increasing to avoid interference among fractures within two wells. And in the final stage, the treatment deployed 100m3 sand, and proppant loading reached to about 41750 Kg/m of net coal. This created a new Chinese record of proppant loading in coal bed methane. Consequently, the first V-Shap well group was successfully treated in china. This work can research the application of special technology well in CBM, evaluate the effect of multi stimulation treatments, and confirm the gas content. It also provides the reliable guidance for the reasonable development of CBM reserve in the future.
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An Effective Acid Placement Technique to Stimulate High-Temperature Sandstone and Carbonate Formations
Authors Ahmed M. Gomaa, Jennifer Cutler, Joel Boles and Hong SunViscoelastic surfactant-based acids have been used in the field for several years, and have been the subject of many laboratory and field studies. An extensive literature survey revealed that corrosion inhibitors and high-temperature dramatically weaken the surfactant structure and significantly reduce its viscosity. Therefore, these fluids are typically limited to placement in relatively low-temperature formations. This study was conducted to evaluate a new VES system that can form a gel and maintain useful viscosity at high temperature. The effects of temperature, initial HCl concentration, corrosion inhibitor concentration, surfactant concentration, and breaker type and concentration on the viscosity and corrosion rate of the new VES were investigated. Additionally, a core flood study was conducted using Indiana limestone and Berea sandstone cores to evaluate the diversion ability of VES system. Experimental results show that because of the low viscosity of the new VES system at live condition, it can be used at an initial HCl concentration of 15 wt% or higher. Even in the presence of a high concentration of corrosion inhibitor, the new VES system maintained its viscosity at 300°F. With no breaker in the system, the viscosity of the new VES system was stable for at least 3 days, and viscosity increased with surfactant concentration. Breakers based on mineral oil caused a smooth viscosity decline, while breakers based on mutual solvent caused instantaneous viscosity reduction. The pre-flush stage of mutual solvent did not prevent gel formation during acid neutralization. Mixing the new VES in 5 wt% NH4Cl brine formed a gel at surface. The new VES acid system increased the pressure drop by a factor of 18 inside Berea sandstone core and resulted in a 60.5 % permeability enhancement. Corrosion inhibitor reduces viscosity of the new VES system, while intensifier has nearly no effect. Also, increasing the concentration of either corrosion inhibitor or intensifier reduced the corrosion rate of the new VES system. Therefore, in some cases, a higher intensifier loading can be recommended to achieve viscosity goals along with corrosion protection.
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Preliminary Analysis of Diagenetic Effects on Basin Scale Over Pressure Dynamics
Authors G. Scrofani, P. Ruffo, G. Porta, M. Riva, V. Lever, A. Scotti and I. ImperialiThis study introduces a diagenetic modeling approach which is then applied to a simple one-dimensional scenario with an alternation of sandstone and shale layers. A key focus of the work is the analysis of the role of critical parameters that may drive pressure and overpressure dynamics in a basin. Due to its one-dimensional nature, the modeling technique presented can be currently applied as a Quality Control (QC) tool to assess the occurrence of diagenetic effects that might affect pressure evolution to assist in improving forecasting of overpressures in a new well in the same area or under similar geological settings. Coupling of hydro-geochemical and mechanical processes with the evolution of temperature enables one to model the effect of basin scale temperature-activated reactions on diagenetic scenarios. The resulting set of partial differential equations includes parameters whose values are always affected by high uncertainty. We provide uncertainty quantification (UQ) of the compaction process through a Global Sensitivity Analysis (GSA) of the system response following incomplete knowledge of a set of model parameters. The model response is approximated through a polynomial chaos expansion of the system dynamics. This decomposition provides (a) a GSA based on Sobol indices, and (b) a meta-model of the system that can then be adopted to perform multiple Monte Carlo realizations of the diagenetic process at an affordable computational time. Our results allow to (i) investigate the effect of parametric uncertainty on the system states, and (ii) perform robust parameter calibration within an inverse modeling framework. This work does not disclose significant data from the field or computer work; it contributes to improve our understanding and modeling of diagenesis of sandstones and shales and basin overpressure evolution.
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Seismic Interpretation Based on Mechanical Deformation Process
Authors Alice Pussacq, Qiang Fu, Emmanuel Malvesin and Solène PanhaleuxIt is a common workflow in commercial software packages to identify stratal features through flattening techniques. However, classic and proportional flattening methods have inherent drawbacks because they do not allow for use of physical laws and rock properties. The use of common mechanical-based restoration methods is also limited because of their low performance. In this paper, we propose use of a mechanical deformation technique based on the finite element method (FEM) to balance seismic data to a hypothetical domain. The conversion makes the interpretation process more reliable for quality control (QC) of structural analysis in an interpretation-friendly environment.
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