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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
561 - 580 of 581 results
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Successful Use of Fundamental Reservoir Management to Flatten the Oil Production Decline in a Mature Field in the Gulf of Thailand
Authors Pongpob Tantrakul and James PritchettThe Platong field is a mature field situated in the northern section of the Pattani basin which is composed of both oil and gas reservoirs. A major characteristic of this field are small faulted, compartmentalized fluvial reservoirs with depletion drive as the main drive mechanism. With small reservoirs and an absence of aquifer support, recovery from primary oil production is low. Commingling production from multiple reservoirs is required to improve production rate and develop each reservoir at a lower cost. Aggressive infill programs are required to offset sharp production decline unless secondary recovery methods can be utilized to boost production. In 2011, the field marked another major accomplishment in reservoir management (RM.) During the year, the base layer oil decline rate was flattened from the preceding 5 year range of 27% to 42% average annual decline rate per year to less than 15%, Figure 1. This significant improvement in the production performance resulted from proactively implementing strong RM fundamentals through cross-functional teams and delivering on waterflood and gas lift projects.
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Evaluating Wellbore Displacement Efficiency of Post-Slurry Overflushing and Its Effect on Injection Pressure in Waste Injection Operations
Authors Lujun Ji, Salamat Gumarov, Talgat Shokanov, Viacheslav Anokhin and Julio RonderosDuring the past decade, waste injection (WI) technology, also known as cuttings re-injection (CRI) technology, has been gradually accepted as an environmentally-friendly and cost-effective ultimate disposal method for drilling-related solids and liquid materials. In waste-injection operations, waste slurry is usually intermittently batch injected into appropriately selected subsurface formations. These slurry injections cause injection pressure and in-situ stress to gradually increase as more and more injected solid tends to accumulate in the near-wellbore fracture domain area. Moreover, solids in the leftover slurry can settle out and plug the wellbore during shut-in periods. These issues challenge injection equipments, wellbore integrity, waste domain containment and disposal capacity, and may hinder or terminate injection operations unexpectedly. Therefore, slurry must be properly overflushed from the wellbore and near-wellbore fracture area effectively and immediately. Effective execution and engineering analysis of post-slurry overflushing have become keys for successfully maintaining critical injection assets. A vigilant monitoring of surface, downhole tubing and annulus pressures makes these analyses possible in a timely and proactive manner. In this paper, post-slurry overflushing with viscous pill and solids-free seawater is numerically modeled for analyzing efficiency of the overflushing and the effects of volume and rheology of the pill on the overflushing in a waste injection well. Moreover, the continuous pressure monitoring in two waste-injection projects in two offshore oilfields provides long-term downhole pressure data. These data were collected and analyzed for instantaneous shut-in pressure (ISIP) after each slurry injection and each post-slurry overflushing, and he effect on in-situ minimum stress and injection pressure was analyzed by comparing ISIP changes before and after overflushing. The studies on ISIP changes confirm the results of the numerical modeling in this paper. Field studies and modeling results also show that overflushing with the appropriate rheologically-designed viscous pill/seawater sequence can decrease long-term injection pressure buildup rate, avoid wellbore/fracturing plugging and extend ultimate disposal capacity.
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The Damage Appraisal on Elemental Sulfur Deposition in High Sulfur Content Gas Reservoirs
Authors Yang Xuefeng, Hu Yong, Zhong Bing, Yang Hongzhi and Wang SongxiaResearch on the elemental sulfur deposition belongs to one of the most important tasks in the development of high sulfur content gas reservoirs. In order to evaluate the formation damage from elemental sulfur deposition in the developing process of the sour gas reservoir accurately, experimental procedures are devised to establish measurement method for determining elemental sulfur deposition by purchasing corresponding experimental accessories. The quantitative research on the elemental sulfur deposition is carried out for the first time at home and abroad. Natural carbonate cores and over-saturated natural sour gas are adopted to observe sulfur precipitation and plugging in the sulfur precipitation damage experiments, which is conducted under the condition of pressure and temperature close to actual reservoir as much as possible. Results illustrate that the sulfur deposition in core has little effect on the porosity with pressure decreased, but great impacts on the permeability. The damage factor of permeability increases with rising initial pressure, and temperature has rarely influence on the sulfur deposition with the same initial pressure. Furthermore, the declining permeability of core results in increasing the damage to the permeability, which means sulfur deposition will cause more harm in low permeability formation.Therefore, it is essential to lay full emphasis on the sulfur deposition during the development of sour gas reservoirs. The reasonable and efficient development strategy can be achieved by alleviating the elemental sulfur deposition as far as possible.
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Characterizing Fluid Distribution in Highly Compartmentallized Chinese Oilfield by Advanced Cased-hole Formation Testing
More LessYingdong oilfield in West China is one of the biggest discoveries recently in china land with probable reserve estimated to be over 100 million tons oil equivalent. This field is small in area coving around 8.1 km2 only. But the oil column is over 400 meters in one of the exploration well and distributed in more than 100 sand zones. Recent seismic work reveals that this reservoir is extremely complex on structure due to the faulty nature. As the consequence of this, significant reservoir compartmentalization is expected and proved by newly drilled appraisal wells. Two wells with only a few hundred meters distance demonstrate completely different hydrocarbon water system. Thus understanding the type of fluid and its distribution becomes the biggest challenge for Yingdong field appraisal and planning the field development in the near future. And testing all these thin zones becomes impractical considering the cost and the time constrains. A recent project of using Cased-Hole Formation Tester to characterize the fluid type and distribution in three wells in this field was accomplished with great success. 20 zones were carefully selected in three critical wells and tested within one-month time. Besides obtaining high quality fluid samples, the hydrocarbon properties, (GOR, composition, bubble/dew point, etc) are also evaluated in real time with the latest downhole fluid analysis technology. It provides timely input to the current production pilot work. The log interpretation results have been revised in quite a few zones with this formation testing answers also.e
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Study on Scour Experiment of Bottom-Supported Platform
Authors Jing Zhao and Shipeng WangThe variation of the seabed may cause the scour around the the foundation of bottom-supported platform in nearshore oilfield, when the platform is fixed on the seabed. For the severe consequences that may cause the slip of platform especially instability of the structure, which need to be paid more attentions in offshore engineering to make it work safely. So it’s important and necessary to investigate the characteristic of scour and take effective measures to prevent it. In this paper, scale models are adopted in experiment to study the scour of bottom-supported platform in currents. It can be observed clearly that the basic characteristic of scour and the evolving tendency of the foundation of the platform through the experiment of two different scales in currents. The area where could be scoured more easily is concluded by analyzing the results. Scour pit pattern and scour depth also can be got through the measurements by ultrasonic topography device. At the same time the maximum scour depth around the foundation of platform can also be inferred based on the scale models theory, which will be helpful for the more sdudy about scour prevention. And it will also have conductive effect for such engineering problem.
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Estimation of the Relative Contributions of Different Hydrocarbon Charges to the SW Qaidam Basin Accumulations Using Micro-Spectroscopy Analysis of Petroleum Inclusions
Authors Lily Gui, Shaobo Liu, Keyu Liu, Zhao Yi, Qingyang Meng and Jiaqing HaoIn a series of paper, the characteristics of petroleum inclusions described by λmax from the UV and CH2/CH3 ratio from the FT-IR spectra. On the basis of optical microscopic, microthermometric, fluorescence spectroscopic and FTIR spectroscopic analyses three types of hydrocarbon inclusions are identified in the study area: namely (1) yellow fluorescencing oil inclusions, (2) blue fluorescencing oil inclusions and (3) gas inclusions, representing two episodes of oil charges and one gas charge possibly related to readjustment of the associated gases down dip. The first episode of oil charge is represented by the predominantly yellow fluorescencing oil inclusions trapped prior to the quartz overgrowth, whereas the second episode is marked by the blue fluorescencing fluid inclusions occurred after the precipitation of dolomite. Both the UV fluorescence and the FT-IR spectra show two distinct oil inclusion groups (yellow and blue) with λmax at 540 nm and 475 nm, respectively and corresponding CH2/CH3 ratios of 1.2 and 2.3, respectively. Microthermometric data indicate that the two groups of oil inclusions have different homogenisation temperatures (Th), corresponding to oil charge around 25 Ma and 10 Ma, respectively for the Gasi and Hongliuquan oilfields, 10 Ma and 5 Ma, respectively for the Yingdong Oilfield, SW Qaidam Basin. The yellow fluorescencing oil inclusions have relatively low maturity and API gravity compared with the blue fluorescencing ones. The current accumulations in the oilfields have maturity and API gravity similar to that of the yellow fluorescencing inclusions. It is concluded that the earlier hydrocarbon charge is thus the predominant contribution to the current accumulations.
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Fully Retrievable ESP: A New Artificial Lift Concept
Authors S. Spagnolo, S. Pilone, L. Corti, G. Liantonio, G. Rizza, G.E. Tita and D.N. KitsoukouThe “Fully Retrievable” ESP System is a new technology, which permits the rigless deployment and retrieve of conventional Electrical Submersible Pump (ESP): a wire-line, coil-tubing or rod should perform these actions. This paper shows the eni experiences in this application and the approach used for the completion design according with the company policy highlighting the benefits and the criticalities faced. Two Fully Retrievable ESP were installed by eni in the following fields: Alaska - OP18-08 - Nikaitchuq Field - onshore arctic environment Congo - FOKM 101 - Foukanda field - offshore. Each of them involved different issues and will be discussed in detail in the following sections. This paper goes all the way through the well definition, completion philosophy and ESP system selection exploring constraints and limitation of this equipment. An economical comparison was performed and the conclusion is that the retrievable ESP should be used in all of those fields where the workover cost is high and the deferred production is important due to rig unavailability. It will be presented that the main benefits of this technology include: Simple ESP retrieving with smaller environmental impact Capability to run temporary systems to clean up or test the well Fine tuning of the ESP based on production data. The benefits of the technology were tested using an internal eni tools for risk analysis based on Monte Carlo simulation: the results are discussed in the last part of the article and highlighted the above expressed consideration and main criticalities.
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The Indicator Diagram Collection Based On Beam Pumping Unit Motor Effective Power Measurement
Authors Yueming Guo and Liang MaConventional beam pumping unit is the most popular lifting equipment at well site, especially in mechanical oil production. To identify its operation, the indicator diagram is an effective tool. Therefore, study on indicator diagram measuring methods has been made as a key subject in major oilfields in China. Currently, force sensors and displacement sensors are commonly used to measure the polished rod load and displacement, so as to generate the indicator diagram. The force sensor is always exposed to the compression and tension of alternating loads, which will damage its elastic coefficient, finally leading to less-precision or even invalid measurements. Besides, this application may bring challenges in installation of devices, work life of the sensors, maintenance and operating cost, which will affect the analysis of well conditions. In summary, the technique cannot satisfy the current requirement of digitalized well management. In view of above issues, this paper proposes a new measurement method. The useful motor power of the beam pumping unit is acquired in real-time manner, and based upon the law of conservation of energy, the motion pattern of the unit is analyzed, to establish a mathematical model containing useful motor power, polished rod load and polished rod displacement. The model can figure out the relationship between beam pumping unit output power and load. Then, in line with field physical calibration, the indicator diagram is measured. This method doesn’t require complex installations on the site. Instead, only electric parameters for input and useful power, apparent power and power factor are acquired to determine the actual polished rod load, according to the correlation between power of the unit and load. Finally, the indicator diagram of the pumping unit is measured indirectly. This method can greatly contribute to the site installation efficiency, work lift of measuring devices and measurement accuracy. This method has been tested in 20 pumping wells. It is found that the equivalent indicator diagram illustrates accordant tendency with the measured indicator diagram; average relative error of area is less than 8%, and average relative errors of maximum and minimum loads after calibration are not greater than 10%. These suggest that the equivalent indicator diagram reconcile with the measured one, and can be used in real time monitoring of pumping well conditions by using useful motor power data. This technology has been effectively applied in an oilfield domestically.
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Systematic Approach to Integrate Surface and Subsurface Well Integrity Management System
More LessProactive well integrity up-keep is an important health, safety, security and environment (HSSE) factor in the industry. Any lapse in well integrity can cause unintentional leaks, which can result in well control situation in terms of safety. This could also lead to aquifer contamination, which is a health and environmental concern. As both subsurface and surface are continuously exposed to deteriorating conditions associated with producing corrosive subterranean fluids from the well and the increasing age of wellstock, the possibility of incidents increases with time. At this point, developing a reliability management system of existing wellbores and wellheads is crucial to ensure optimum HSSE compliance. The objective of such a system is to optimize productivity and add value, by enlisting the causes and the available tools and methods against given well conditions, to ultimately extend the life of the wells, reduce HSSE concerns while reducing operating costs associated with post incident rectification, cleanup and improve reliability. This paper presents an integrated approach that Saudi Aramco employed to address surface and subsurface well integrity by the incorporation of these types of management systems. In this approach, subsurface integrity issues are addressed through careful well design, continuous monitoring, and re-use of existing wellbores. This approach also provides a wider investigation of surface assets by revealing solutions to surface integrity problems, including unsecured wellheads, leaking wellheads and Christmas trees and limitation of offshore platform design. To provide a broader insight of well integrity, this paper also focuses on the operational and well intervention phases of a well’s life, and discusses evolution of the well integrity management system. The data management processes used to monitor the well integrity system is also discussed.
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The Study of Drag Reduction Ability of Naturally Produced Polymers from Local Plant Source
Authors Harvin Kaur, Gurchran Singh and Azuraien JaafarDrag reduction is observed as reduced frictional pressure losses under turbulent flow conditions and hence, substantially increases the flowrate of the fluid. Practical application includes water flooding system, pipeline transport and drainage system. Drag reduction agent, such as polymers, can be introduced to increase the flowrate of water flowing, reducing the water accumulation in the system and subsequently lesser possibility of heavy flooding. Currently used polymer as drag reduction agents is carboxymethylcellulose, to name one. This is a synthetic polymer which will seep into the ground and further harm our environment in excessive use of accumulation. A more environmentally-friendly drag reduction agent, such as the polymer derived from natural sources or biopolymer, is then required for such purpose. As opposed to the synthetic polymers, the potential of biopolymers as drag reduction agents, especially those derived from a local plant source, are not extensively explored. The drag reduction of a polymer produced from a local plant source within the turbulent regime will be explored and assessed in this study using a rheometer where a reduced a torque produced can be perceived as a reduction of drag. This technique of assessment for drag reduction ability is also unique as many literatures on drag reduction rely heavily on flow loop data which sometimes, require time and high cost for the fabrication of the flow loop. The new method proposed is less time consuming and is more practical which is producing carboxymethylcellulose from the banana peel. The cellulose powder was converted to carboxymethylcellulose (CMC) by etherification process using sodium monochloroacetate and sodium hydroxide. The carboxymethylation reaction then was optimized against the reaction temperature. Then, the biopolymers will be rheologically characterized where the viscoelastic effects and the normal stresses produced by these biopolymers will be utilized to further relate and explain the drag reduction phenomena. The research is structured to focus on producing the biopolymer and also assess the drag reduction ability of the biopolymer produced. Various temperatures when synthesizing the biopolymers will be studied as a drag reduction agent to obtain the optimum value of which the biopolymer works the best. The rheological behavior of the biopolymers will also be analyzed and relate to the drag reduction ability. The results are intended to expand the currently extremely limited experimental database for biopolymers in turbulent flow.
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Innovative Capillary Deliquification Safety System Resolves Liquid Loading Problems With a Cost-Effective Solution that Maximizes Production While Maintaining Well-Safety Requirements
Authors Pasquale Imbò, Daniele Magnani, Maurizio di Iorio, Cesare Russetto and Gene TucknessMany mature gas wells worldwide have had to be shut-in due to water loading in the production string, which occurs when the liquid’s hydrostatic column pressure equals that of the reservoir pressure, stopping production. Periodically injecting surfactant chemicals from surface has been tried but is only a temporary solution. Continuos injection of a downhole foaming agent can be used to lift the water and restore gas production. If an injection line is not part of the completion string, an external injection line can be installed either with a rig workover or a rigless through-tubing installation. The first solution requires significant rig expense, and the second can cause loss of downhole safety-valve functionality. A more cost-effective, safer problem resolution method was needed. This paper describes the first ENI field trial of a Capillary Deliquification Safety System that can be retrofitted into existing wells with rigless intervention to quickly reinstate production. This method maintains safety valve functionality and eliminates an expensive well workover. The installation equipment includes a modified wireline-retrievable surface-controlled sub-surface safety valve (WR-SCSSV) with capillary tubing attached below. The injection method operates via the control system for the WR-SCSSV. The installation, which uses the existing control line of the safety valve to inject chemicals, does not require wellhead modification. The trial installation of the new system took place in a shut-in well in a Barbara offshore field in the Adriatic Sea. The trial showed that the system could provide a cost-effective alternative to well workovers and occasional surfactant treatments and will significantly increase hydrocarbon recovery from the reservoir while maintaining the well’s safety level.e
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Successful Offshore Deployment of the First Bottom Discharge ESP in Saudi Aramco
Presented in this paper is the success story of the offshore deployment of a Bottom Discharge Electrical Submersible Pump (BD ESP), the first of its kind in Saudi Aramco. Based on an immediate need for pressure support at low cost, this pump was selected to provide the required injection volume and pressure for a water injection system using nonpotable water (NPW). Water from a shallow depth (4,500 ft) was injected into an oil zone located below (7,400 ft), with no water at the surface, eliminating any need for treatment at the water injection plant. The concept of using bottom discharge was considered as part of the ongoing efforts to evaluate different completion strategies for local and independent injection. Typically, a centralized water injection plant and pipeline network stretched over long distances is common practice within Saudi Aramco. These efforts were driven by the business need of a particular field to provide sufficient water injection to the producing reservoirs, with the consideration of low capital investment, and a short implementation time frame. Water conservation efforts require the Company to use either treated seawater or NPW (water so non-potable that it would be more expensive to attempt to treat it than use treated seawater). Well X, an existing offshore completion suitably located close to oil-water contact (OWC) of the Arab-D reservoir and within the perimeter of the aquifer (TDS = 24,700 ppm), was selected for this application. These factors made the well an excellent candidate to test the BD ESP completion and to provide 8-12 thousand barrels per day (MBD) of water injection to support the Arab-D reservoir. The aquifer was perforated and the BD ESP completion was deployed successfully in tandem with a satellite communication surveillance system, to validate injectivity, optimize pump performance, and gather reservoir data for further analysis.
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Moving Toward Intelligent Field Applications: MPFM for Production Rate Testing and Beyond
Authors Karam S. Al Yateem and Nami Al AmriPrior to the broad implementation and utilization of Multiphase Flow Meters (MPFMs) in Saudi Arabian offshore oil fields, rigorous testing was performed utilizing in-series MPFM systems in conjunction with Saudi Aramco’s testing fleet that are equipped with a conventional separator testing trap. Sets of data were collected simultaneously from different wells through different MPFMs, completed in different reservoirs, for about a year to compare and validate the results. The accuracy of the MPFM proved to be within engineering acceptable margin of error for all parameters and in most cases matches the conventional methods of testing results. Since then, offshore platforms are being retrofitted with a MPFM to be able to test all the wells on the platform by selectively switching them one at a time through a test line physically and remotely. Since its pioneer implementation almost a decade ago, MPFM testing accuracy and the technology has improved considerably. The use of the MPFM has many advantages in the testing operations, especially during periods where the demand is high. Accurate and frequent well testing becomes decisive in times of maximum production rates since the results from well tests facilitate determining which wells are under significant decline and which have increasing water cut in a real time fashion especially for fields with large number of wells. The quick identification of these problems leads to taking immediate action to restore the wells’ productivity toward maintaining optimal production rates. The MPFM offers real time well performance monitoring through the Supervisory Control and Data Acquisition System (SCADA) and has an added benefit of shorter test rate stabilization times. Additionally, the induction of the remotely operated selector switch in the units recently allowed full automation of the process of switching remotely different wells for well testing on a multi-well platform. It also minimizes human involvement and provides operational flexibility. In addition, it reduces the waiting time for wells’ switching due to natural limitation factors, such as bad weather offshore. This paper largely addresses the reliability and accuracy of MPFMs as compared to a conventional separator and to a portable MPFM as well as using electrical submersible pump (ESP) optimization application to identify what method gives more accurate testing. Further optimization of ESP well’s performance with frequent testing is also accomplished, which in turn improves the sweep efficiency of the reservoir, accelerates the production of recoverable reserves and environmentally help improve pump run-life. The paper will also elaborate on the benefits attained from installing MPFM in mature offshore oil fields with a focus on special cases like the MPFM in-series testing, testing artificially lifted wells, smart well completions and newly completed wells. It will illustrate the benefits attained with focus upon special cases like the MPFM in-series testing, artificial lift wells, smart well completions and newly completed wells exhibiting an indirect support in achieving the production targets. Different principle and theory behind MPFMs will be highlighted with advantages along with a vision of the way forward. Further to the benefits of installing MPFM, the paper will also discuss lessons learned and improved guidelines imposed over wellhead sampling (WHS) benefiting from the success of the MPFM. These guidelines effectively minimize sampling in wells equipped with MPFMs.
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Testing Methodology for Smart Wells Completion toward Attaining Optimal Production Rate Setting for Maximum Hydrocarbon Recovery
Authors Samih Alsyed and Karam YateemEvery oil company strives to produce its fields smartly, effectively and efficiently to ensure maximum recovery and minimize any unrecovered reserves. Being the largest integrated oil company with the most reserves, Saudi Aramco is in the forefront of such efforts by utilizing real time data and controls, also referred in our industry as smart or intelligent wells and controls. Some of these efforts are evident from the recent development of Haradh III increment (2006); part of Ghawar field, which is considered to be the world’s first fully intelligent field1. Even prior to that, individual intelligent field ventures started in many fields and Safaniya, the world’s largest offshore oil field, is not new to that. Safaniya holds a wide range of intelligent field equipment and is expected to be fully automated in the near future. Completing wells with smart completion jewelry is one such effort. With an increasing number of smart well completions in Safaniya, the need is to ensure the maximum benefit is gained from them and the completion design is optimized early on. This paper is an effort to detail the procedure adopted to conduct the first test on smart well completions in one of Saudi Arabia’s offshore fields. The paper details the processes and practices of testing smart well completions for inflow performance and capacity of all laterals and the operation of the downhole valves. To evaluate the completion practices in horizontal multilateral wells followed by simulation runs with various completion configurations, the test was run for two different wells with two different completion configurations. This practice helped optimize design completion (tubing size, number of multilaterals) of dual lateral wells with inflow control valves (ICVs) to maximize production.
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The Horizontal Massive Multistage Fracturing Meet the Changling Tight Gas Field Development Strategy
Authors Feng Wang, Yingan Zhang, Hongbo Zi, Qiqiang Pang, Guangyu Liu, Zhao Peng Zhu, Biansheng Li and Yongwei DuanThe deep tight gas reservoir in southern Songliao basin has features of deep burial, dense lithology, poor physical property, high in-situ stress and no natural deliverability. Early development practice certificated that neither horizontal well nor conventional vertical fracturing can achieve promising stable production. This paper presents the successful case history in which the horizontal massive multistage fracturing techniques are developed. This includes optimizing horizontal section, optimizing the horizontal well completion and fracturing design, the slim open-hole packer sliding sleeve multistage fracturing technique and the large scale traversing fracturing technology. Also the deep well fracturing operation safety and surface security technique are discussed in the paper. At present 9 wells 100 stages has been operated, and achieved the target of most 15 stages and maximum1451m3 proppants in a single well. The stable production rate of the fractured horizontal well was 5 times more than the around vertical well. This technology can fracture more stages, shorten operation time, lessen formation damage and reduce friction drag. So it maximizes the reservoir stimulation volume, which provides technical support for large-scale development of the tight gas sandstone reservoir in Changling gas field.
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The Influence of Wellbore Stability on the Feasibility of Extended Reach Drilling Wells: A Case Study from Offshore Vietnam
Authors Feng Gui, Abbas Khaksar, Todd Gilmore and Ngo The DuongWellbore stability is important for successful horizontal and extended reach drilling (ERD) wells. Hole instability problems associated with ERD wells can sometimes change the original development plan because of complications and unforeseen operational and geomechanical issues. This paper presents a case study from offshore Vietnam, where historically, no significant wellbore stability problems had been reported for vertical and low-angled wells. There were plans to develop the field by drilling highly deviated and ERD wells from one platform. However, instability problems and significant non-productive time from frequent pack-offs, tight holes and stuck liners were encountered while drilling one of the designed wells. The hole was sidetracked three times and finally drilled at a lower angle than originally planned. Geomechanical analysis using core, well log, drilling data and experiences were used to build a field scale geomechanical model characterizing the in situ stress, pore pressure and rock mechanical properties in both the overburden and reservoir sections. Stress-induced borehole failure observed in image logs from an offset well and diagnostic analysis of failure mechanisms from cavings recovered from the problematic well provided significant insights into the likely nature of instability problems in the ERD well. Hole instability problems were attributed to the failure of weak bedding planes and anisotropic rock strength in the shales interbedded with sandstones. To control the weak bedding and anisotropic failure, stronger mud weights were needed than were in the original plan. The required mud weight for maintaining stability varies depending on wellbore trajectory and bedding characteristics. The usagee of high mud weights is unfavorable because of possible formation damage that could occur and the risk of fracturing the reservoir (because of lower fracture gradient). Consequently, the original ERD plan had to be revised and new optimum well trajectories designed that took into account any drilling issues, in addition to completion and productivity requirements.
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Advanced Completion and Fracturing Techniques in Tight Oil Reservoirs in Ordos Basin: A Workflow to Maximize Well Potential
Authors Hai Liu, Yin Luo, Xianwen Li, Yonggao Xu, Kewen Yang, Lijun Mu, Wen Zhao and Shuxun ZhouIn recent years, great efforts have been focused on tight oil reservoirs in Ordos Basin, which is located in North Central China. Although historical field development in these tight oil reservoirs was still economical, average production after hydraulic fracturing is quite low and most of wells produce just at the margins. In order to understand production potential through appropriate completion and fracturing techniques, a pilot project was initiated recently on two horizontal wells drilled in parallel, with three vertical wells placed between two horizontal wells along the lateral for real time fracturing monitoring. This paper describes how the treatment design was optimized based on detailed formation evaluation and fracture simulation using a 3D unconventional fracturing design workflow. It presents real time fracture mapping results through a dual monitoring well setup on total 26 stages of fracturing treatments, and also illustrates how the results were utilized to adjust and optimize treatment design during and between treatment stages. The paper demonstrates the application of a unique Unconventional Fracture Model (UFM) that was developed for design and evaluation hydraulic fracturing treatment in unconventional reservoirs. The model incorporates predefined natural fracture patterns and interaction criteria for hydraulic and natural fractures. The paper also discusses the outcome of simultaneous treatments tested in four stages compared to other stages pumped in sequences. Initial production tests on both wells show 124.5 m3/d and 103.2 m3/d respectively, which are significantly higher than all the wells completed in tight oil reservoirs in the basin, of which the production varies from 5-8 m3/d in vertical wells to 32 m3/d in horizontal wells on average. In-depth reservoir understanding, advanced design and evaluation workflow, and appropriate completion and fracturing technique are the key of this success, which has set a milestone for developing such tight oil reservoirs in Ordos Basin.
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A New Method for Earlier and More Accurate EUR Prediction of Haynesville Shale Gas Wells
Authors Xueying Xie, Michael D. Fairbanks, Kevin S. Fox and Rena L. KoinisHaynesville shale gas wells are operated over a wide range of back pressures, varying from 8000 psi or higher at early time to 1000 psi or lower at later time. Traditional Arps Delcine Curve Analysis (DCA) presumes constant back pressure, and therefore overpredicts Estimated Ultimate Recovery (EUR) for Haynesville wells when applied at early time, prior to reaching line pressure. A new method has been developed to forecast well EUR earlier and more accuratley by using pressure normalized rate instead of actual rate. In this method, the actual rate is normalized to the rate corresponding to a constant operating pressure.
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Wellbore Strengthening and Continuous Mud Circulation Allow to Save an Expandable Liner: Field Application Offshore Italy
Authors Giuseppe De Grandis, Alberto Maliardi and Angelo LigroneWellbore strengthening techniques have been used in recent years to increase the capability of wellbores to maintain higher pressures. By increasing the fracture resistance of formations, operators can save rig-time and large volumes of drilling fluids. The Luna-41 well, offshore Italy, intersects a critical interval comprising high pressurized formations overlaying a lower pressure depleted zone. The initial plan for the well was to divide this interval into two separate hole sections using two different mud systems. A casing string would have been set to isolate the shallower high pressure region followed by an expandable liner to isolate the over pressured shales laying above the depleted reservoir level. An alternative design was proposed that required only one fluid system and a single casing string, thus saving an expandable liner. Thanks to the wellbore strengthening application and the proprietary continuous mud circulation device, the accomplished well program allowed an 8-day rig-time reduction and a 3-MMUSD cost saving. A specific modelling tool developed for wellbore strengthening applications was used to assist with fluid design. The tool calculates the width of microfractures induced by differential pressure and the Particle Size Distribution (PSD) of carbonate materials required to plug such microfractures and ultimately strengthen the wellbore. The mud formulation for Luna-41 was tested in the laboratory using a Pore Plugging Apparatus (PPA) and aloxite discs with pore sizes corresponding to the calculated microfracture width. The fluid used to drill the critical interval was a salt saturated system based on polyglycerol complex and supplemented with a polyamine inhibitor. The field application was a success. The depleted zone was drilled without incurring lost circulation. This paper describes the results of the field application as well as the fluid engineering process and laboratory testing to highlight the benefits – such as accessing depleted reservoirs and saving casing strings – that wellbore strengthening combined with a continuous mud circulation system can bring to the industry.
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Production Enhancement Using a Multiphase Helico-Axial Pump in a Remote Hilly-Terrain Oil Field in Saudi Arabia
Some of the wells in the southern part of a remote field in Saudi Aramco are either producing intermittently or ceasing to flow against the high trunk line pressure. Saudi Aramco had considered various options along with horizontal thrust boring direct drilling under the sand dunes to reduce this high back pressure. A helico-axial multiphase pumping (MPP) technology was selected for the trial test in this field since in 2005 the horizontal thrust boring technology was limited to distance up to 2 km. In addition, the multiphase pump provides the flexibility such as reducing the back pressure and particularly, the helico-axial technology has a wider operating envelope as some wells will be weaker in the long run. Saudi Aramco has successfully re-commissioned the MPP in January 2011, and it was trial tested for a nine month period at the remote area with three dead wells and two marginal flowing wells. A total of 7,000 to 8,000 barrel oil per day incremental production was realized by lowering the back pressure on these wells using the MPP. This paper describes the testing, field operational experience and recommended improvement of a rotodynamic (helico-axial) MPP system at a remote, hilly terrain onshore oil field in Saudi Arabia. This paper is a sequent to SPE-117462 paper, Deployment of Rotodynamic Multiphase Pump in a Remote Hilly-Terrain Oil Field in Saudi Arabia,” presented at the 2008 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, UAE.
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