bluuebunny/crossref_metadata_2025 huggingface dataset:
Unconventional Resources: The Next Generation. Assessing Coal to Liquids, Oil Shale, Underground Coal Gasification, Microbial Coal Conversion and Other Technologies within the SPE-PRMS.
Authors: Peacock Douglas , Majid Azlan , Gaffney Gaffney
Published: October 2015

As unconventional resources such as Shale Gas and Coal Bed Methane become mainstream, many companies are looking towards the next generation of resource types. Coal to Liquids, Oil Shale, Underground Coal Gasification and Microbial Coal Conversion are examples of resource types that are being assessed and in the early stages of commercial exploitation within the Asia Pacific region. How can companies looking to exploit such resources assess their projects within a common framework? Such projects run the risk of falling between the cracks of petroleum assessment guidelines such as the SPE-PRMS and mining guidelines such as JORC.

These resources often do not occur naturally as hydrocarbons. They typically involve a mining, or in-situ, extraction process followed by a direct or indirect upgrading process whose end product is a saleable liquid product such as synthetic crude oil. In some cases, in-situ extraction is possible. Whilst such mining and upgrading processes are clearly included within the SPE-PRMS for such deposits as tar sands and bitumen (which are already naturally occurring hydrocarbons), the situation is less clear when the raw material is not naturally occurring hydrocarbons.

Coal to Liquids involves mining the coal/lignite followed by an upgrading process to produce synthetic hydrocarbons. Oil Shale is essentially an immature kerogen-rich source rock which requires artificial maturation to generate hydrocarbons. Various techniques are available, either in-situ or mining followed by an upgrading process at the surface. Underground Coal Gasification is an in-situ process used in non-mined coal seams to generate gases including methane through injection of oxidants and steam to fuel an underground combustion process. Another emerging technology is microbial coal conversion.

Although they do not fully satisfy all of the definitions of the SPE-PRMS, the authors believe that the principles of the SPE-PRMS can be used to assess such resources. The project can be evaluated as a whole i.e. from mined raw material through upgrading process to saleable end product.

Further clarity and definition within the SPE-PRMS would assist such assessments. Overlap and integration with JORC and other mining codes would also aid understanding and transparency. There are also challenges required during the assessment of such projects. Traditional petroleum industry skills must be supplemented with expertise in mining and product upgrading in order to perform a full analysis. With many companies in the Asia-Pacific region, especially Australia and China, assessing such resources and looking to commercialise them, improvements in their understanding and assessment would be beneficial to all stakeholders.
Accurate Prediction Model for Rheological Properties of Drilling Fluids at High Temperature and High Pressure Conditions
Authors: Fan H. , Zhou H. , Meng X. , Gao J. , Wang G.
Published: October 2015

Tremendous amounts of hydrocarbons are located in deeper formations, such as in Tarim basin of China, some reservoirs buried so deeply (>7600m) that we experience higher temperature (>180°C) and pressure (>180MPa). And the drilling fluids rheological properties are often affected by HTHP, the careful research on the drilling fluids rheological properties at HTHP is very important for precisely predicting ECD as well as controlling the bottomhole pressure.

An accurate prediction methodology of HTHP drilling fluids rheological properties was formulated, which can accurately predict the HTHP rheological parameters. First, the rheological properties of a high density (2.04sg) oil-based drilling fluid at high temperature and pressure were measured. The experimental results indicate that the pressure effect on the rheological properties at ambient temperature was considerable, and this effect could be gradually reduced with the increase of temperature. Second, based on the experimental results, a comprehensive prediction model of HTHP rheological parameters was established, a novel mathematical model for calculating the HTHP shear stress of different shear rate was formulated, the influence of high temperature was taken into account first and then the comprehensive influence of high temperature and high pressure was taken into account too. Based on the mathematical model, we can obtain the HTHP shear stress of different shear rate easily. Based on the HTHP shear stress, a utility HTHP rheological model optimization method and parameters calculation model was proposed. Because of this model related the HTHP shear stress to the influence of HTHP directly, and then calculated the rheological parameters, rather than relating the specific rheological parameters to HTHP as the traditional models, therefore the prediction model is applicable for all rheological model (Bingham, Power-Law, Herschel-Bulkely, Robertson-Stiff et al.).

Finally, a novel HTHP rheological properties analyzing system was developed, through which the HTHP rheological parameters can be obtained easily, a series predictions of this model have been compared with the experimental data about different type drilling fluids (oil-based, synthetic-based fluids), and the results show very good agreements with the experimental data. Therefore it can be used to accurately predict the rheological parameters and calculate the hydraulic parameters in the HTHP conditions while drilling.
First Large-Bore Expandable Liner Hanger Deployment Offshore Gabon: Case Study
Authors: McCormick John , Seinuah Alex , Humphrey Ryan , Bledou Manfred
Published: October 2015

The capability to reliably deploy large-bore hangers in offshore applications is critical to project success (McCormick et al. 2013). This case study discusses the the deployment of a large-bore expandable liner hanger (ELH) for the first time in a West African country and how the deployment of a 16-in. liner inside 20-in. casing at a water depth of 1,752 m was made possible by the use of an ELH system first deployed in 2010. Some of the design features critical to this application, initial preparation and mobilization of the ELH system in a remote location, and the execution of the job will be discussed.

The system was assembled, inspected and tested using a mobile workshop as a contingency hanger for an offshore well on the Ivory Coast. When a conventional hanger could not be set and the running tool parted in an offshore well elsewhere in West Africa, the well was ultimately abandoned and a second well spudded. The large-bore ELH system was shipped from Ivory Coast to the other country for installation in the new exploratory well, which was constructed using a fifth-generation drill ship. The cement job was challenging, with a significantly higher density of cement over the well fluid, which caused the string to rise in the rotary table while pumping the cement job.

This case study specifically addresses issues observed when running a conventional hanger by providing a large-bore ELH with a smooth profile, resulting in lower pressure losses and significant tensile capacity for the hanger and service tool. Equally important is the tensile capacity of the hanger resolved a problem seen with a different hanger in the previous 16-in liner run. The system used to run this expandable liner hanger also resolves the problems often experienced offshore when attempting to seat a casing or liner hanger in an exact location, such as a mud line receptacle. This system allows the liner hanger to be placed anywhere in the parent casing (Johnson et al. 2011).

This paper discusses information that will help to increase operator awareness concerning alternatives to traditional liner-hanger methods. As the industry pushes further into deepwater exploration and developmental wells, solutions for improved reliability and increased versatility are being implemented. ELH large-bore technology will help to increase the versatility and efficiency for current operations by improving liner-hanger placement flexibility, increasing the maximum-allowable flow rate, and providing more efficient zonal isolation.
The Numerical Simulation for Multi-Stage Fractured Horizontal Well in Low permeability reservoirs Based on Modified Darcy's Equation
Authors: Hailong Liu , Shuhong Wu
Published: October 2015

With further progress of oilfields' development all over the world, more and more low permeability reservoirs are being put into production and a large number of multi-stage fractured horizontal wells were drilled. However, fluid flow in tight sandstone porous media does not obey Darcy's law any more, and instead conforms to the one of low-velocity non-Darcy seepage. So the multi-stage fractured horizontal well numerical simulation method has been developed.

In this paper, Based on the nonlinear percolation theory, a new nonlinear seepage model of low permeability reservoir was established. Then, on the basis of core displacement laboratory experiment data and practical field data, an ideal three-phase and three-dimensional numerical reservoir simulation model for multi-stage fractured horizontal well was built. Under the same low permeability reservoir, taking the impacts of pressure sensitive effects and the threshold pressure gradient into consideration, the quasi-linear numerical model, Darcy numerical model and the non-Darcy numerical model were conducted. The effects of parameters including pressure sensitive effect, the threshold pressure gradient, were fully investigated. At last, the simulation results of pressure, water cut and recovery ratio for the non-Darcy numerical model of multi-stage fractured horizontal well were given.

Research shows that most flow areas belong to nonlinear flow area; compared with the results of Darcy model, when considering non-linear flow, the energy consumption is higher, and the pressure level is lower, and the liquid production is smaller, and the water cut rising is slower. Sensitivity analysis shows that: For quasi-linear flow, Darcy flow and non-Darcy flow, with the increasing of non-linear flow coefficient, the flowing bottomhole pressure decreases quickly. When the injected fluid of the injection wells reaches the wellbore, the flowing bottomhole pressure increases quickly. However, the time of water front reaching the wellbore is different. For the non-Darcy flow, the recovery ratio is positive with the starting pressure gradient of water phase, but negative with starting pressure gradient of oil phase. With pressure sensitive coefficient decreasing, recovery ratio increases quickly. If producing pressure differential is maintained at proper value, then the effect of the pressure-sensitive on the permeability is reduced, which can help to improve recovery ratio. With the threshold pressure gradient becoming smaller, the recovery ratio becomes higher. The effect of the threshold pressure gradient on recovery ratio can be smaller or "eliminated" by using fracturing or advanced water injection.
3D Fracturing Design With Consideration of the Diverse Fluvial Depositional Environments and Flow Units in Tight Gas Reservoirs
Authors: Gou Bo , Deng Yan , Guo Jianchun , Lu Cong , Yu Ting , Wang Xingwen
Published: October 2015

XS gas reservoir in Western Sichuan Basin is a typical tight sands hotspot in China, of which the target stratum, namely the 3nd Member of Penglaizhen Formation is braided channel deposition. The sand body with good communication along the river channel is opposite perpendicular to the channel. Moreover, the reservoir with horizontal drilling shows diverse type of sand bodies and strong heterogeneity in vertical and lateral directions. Multi-stage hydraulic fractured horizontal wells have been proven to be effective to enhance gas recovery in tight sandstone gas reservoir. However, one major obstacle has been the previous inability to place the hydraulic-fracture in the complex fluvial tight reservoir to maximize gas production.

This paper provides a 3D fracturing design method (3D FDM) considering the influence of various sand-body and flow units on the hydraulic fracture propagation in fluvial tight reservoirs. Firstly, the reservoir was classified into three grades based on its porosity and permeability. A 3D geostatistical reservoir model which was divided into three types, was developed with the sandstone body distributions in vertical and lateral directions. Subsequently, the flow unit boundary was determined by the sand-body permeability and thickness. Then the detailed fracture parameters were implemented in the 3D models and reservoir simulation was used to select the fracture number, space, length and conductivity to achieve economical flow rates. At last, the fracturing simulator was utilized to confirm whether the treatment parameters were appropriate.

Results show that the flow unit boundary is a log function of sand-body permeability and thickness. The influence of reservoir grades on fracture space is obvious, which indicates that the fracture space is large in high-grade reservoirs. Comparing various qualities of reservoirs, the fracture length and conductivity in poor-quality reservoirs is considered to be the most significant.

Comparison with the fracturing wells with conventional fracturing design method in Xinma gas reservoir, the post-production of the well with 3D FDM increases by 41%, and it shows that 3D FDM is appropriate for the gas development in Penglaizhen Formation.
Openhole Multistage Acid-Fracturing Increases Hydrocarbon Production in Deep Naturally Fractured Carbonate Horizontal Wells in Ta-zhong Gasfield of Tarim Basin, West China
Authors: Mingguang Che , Fu-xiang Zhang , Yonghui Wang , Xiangtong Yang , Raoyun Zhu , Runqiang Fan
Published: October 2015

The naturally fractured carbonate reservoir of Ta-zhong has been developed for over ten years due to new technologies. Since 2008, a program was undertaken to test openhole multistage acid-fracturing technology in the Ta-zhong gasfield to determine if deep fractured carbonate reservoir could be effectively developed by horizontal wells.

This paper will introduce the challenges including the segregated completion through optimized design and individual acid-fracturing treatment through simulation, production history of stimulated horizontal wells and the comparisons with offset wells. Ta-zhong carbonate reservoir is buried from 5000m to 7000m TVD with low matrix permeability and porosity, the hydrocarbon is mainly stored in the interconnected natural fractures and vugs, so a novel segregated completion method was gradually formed during the development from the reservoir description.

To avoid circulation loss or blowout during drilling horizontal well, the horizontal interval was usually close to the top of reserves with natural fractures and vugs by control while drilling. The reserves and numbers of segments will be distinguished by 3D seismic, well course and stress direction, and then the distances between reserves and horizontal interval was calculated through horizontal well track superimposed on the seismic profile, each section divided by openhole packers need special acid-fracturing technique to get sufficient height or length to communicate the hydrocarbon reserves. Simulation work gives the results which pad and ground cross-linked acid multi-alternative injection fracturing is favorable for longer length, and pad acid-fracturing is favorable for higher height. The performances of frac fluid and ground cross-linked acid are also showed in the paper, the residual viscosity of gel fluid is greater than 150mPa·s in the conditions of 140? and 170s−1 shear, and ground cross-linked acid's is more than 200mPa·s in the conditions of 120? and 170s−1 shear.

Production comparisons showed that stimulated horizontal wells extended the production life of development wells and improved development effectiveness. Several years’ production history analysis of TZ62 block highlighted that the average hydrocarbon rate of multistage acid-fracturing horizontal wells was several times the stimulated vertical offset wells.
Study of Sour Gas Kicks Taken During Managed Pressure Drilling Operations
Authors: He Miao , Liu Gonghui , Li Jun , Li Jiwei , Zhang Tao , Liu Wei , Li Mengbo
Published: October 2015

The well control safety is always an important issue in the drilling engineering, especially for the sour gas reservoir in deep carbonatite, in which the formation gas invade into the wellbore quite easily and that is difficult to be detected due to narrow mud window and high solubility of sour gas respectively. However managed pressure drilling (MPD) well control is an effective new method to deal with gas kick problems, which allows circulating a certain influxes out of the wellbore without shut-in procedure while keeping the bottomhole pressure relatively constant. Therefore it might be an appropriate way to be used in sour gas kicks with high H2S content.

A transient multiphase flow model for complete kick circulations of MPD well control operations is proposed. The presented model takes gas solubility in Water Based Mud (SBM) into account, which is often ignored in most hydraulics calculations, by using PR equations of state (EOS) to predict the PVT behavior of the drilling fluid with dissolved gas. The validity of the model including liquid volume fraction and pressure drop have been both verified with large-scale flow loop experimental date at The University of Tulsa.

There are three main variables (maximum pit gain/casing pressure/casing shoe pressure) during complete circulation of a kick that are calculated and analysed. As the content of H2S increases, the maximum pit gain/casing pressure both decrease while the maximum casing shoe pressure remains almost the same. The peak value of casing pressure appears obviously later than the moment that gas front migrates to the wellhead. Moreover, the effects of degrees of choke opening on the annular pressure during the MPD well control operations are studied.

As a result, this study has an important guiding significance to improve MPD well control theory for sour gas reservoir development with lower non-productive time (NPT).
2004-2014: A Decade of Drill Pipe Grades and Industry Standards Evolutions to Address Increasing H2S Challenges
Authors: Flores Vincent
Published: October 2015

Hydrogen Sulfide (H2S) can interact with steel tubular, such as drill pipe, and through the unfavorable combination of different factors a crack can initiate in the material and propagate until catastrophic failure, even with stresses largely below the yield limit of the material. The combination of tubular failures due to Sulfide Stress Cracking and the rising HSE concerns when dealing with sour gas has led the industry to develop new grades of drill pipe with enhanced resistance to SSC.

Material selection for drill pipe in a sour environment is significantly complex, mainly due to the absence of dedicated international standard. Nonetheless, at a regional level the "Industry Recommended Practices" Volume 1 has been published in 2004 in Canada. The standard was created to insist on people safety, and provide specification and guidelines to manufacturers on material properties, quality control, testing and inspection of drilling products intended to be used in critical sour wells.

Sour Service Drill Pipe as defined in the IRP have been used for a decade in Canada, as well as in other regions and continents, along with a variety of other proprietary Sour Service grades of drill pipe and BHA. This paper proposes a review of different field cases in the Middle East and Asia, as well as an outlook of the different practices for material selection and qualification guidelines which have emerged since the past 10 years.

More recently, with the increasing demand of domestic gas in different part of the world, some highly sour oil and gas reservoirs are being explored with H2S contents beyond what could have been imagined a decade ago. To explore, appraise and eventually develop such fields, most of the time combined with complex well profiles or deeper reservoirs, significant technical challenges need to be addressed regarding drill pipe integrity and operations safety. This paper proposes a non-exhaustive review of the newest emerging industry trends as far as international standard guidance, regional normative initiatives, and new steel developments.
A Simple Method for Gravel Pack Evaluation Using Gamma Ray Tool
Authors: Rushatmanto M. , Ruau O. , Muryanto B. , Abergel T.
Published: October 2015

Total E&P Indonesie produces gas from mature fields in the Mahakam PSC concession. Currently sand production can be a major problem, as a result of reservoir depletion and/or shallower reservoirs with unconsolidated sand are produced to maintain the production plateau. Sand production could jeopardize the completion hardware downhole as well as to cause problems at surface facilities which lead to well integrity and safety issues. Gravel pack (GP) is the most common sand control completion implemented in TEPI to avoid sand production. It has been used widely to deliver wells with good productivity, efficient operation and cost effective for various stake of each zone and of the well itself.

There are well known methods to evaluate effectiveness of gravel placement in the screen-casing annulus with the aim of detecting the top of proppants, voids and to quantify the quality of gravel packing within the packed interval. Darcy's equation and volumetric calculation during placement of gravel pack can be used to estimate top of proppants in the blank pipe above top of screen. Several logging measurements exist and the most common to evaluate gravel pack quality is conventional method using Density Gravel Pack Tool. Other existing tools are Compensated Neutron Tool, Pulse Neutron Log (silicon activation) and Radioactive Tracer. The existing tools require a dedicated run, additional time and cost as well as an operation constrain related to radioactive source permit and handling. Each tool has pros and cons, mainly related to accuracy and resolution of its measurement, completion hardware and type of fluid inside wellbore.

Gamma ray is not categorized as a GP evaluation tool, the tool measures natural formation gamma ray; therefore radioactive source is not required like for existing tools. The application as a GP evaluation tool only works for ceramic or man-made proppants (made from clay) and does not work for any natural sand proppants. Radioactivity of ceramic or man-made proppants is relatively high compared to reservoir sand, therefore any increasing gamma ray response is associated to proppants presence in the screen-casing annulus but not the degree of gravel packing. This method can be used for time lapse monitoring using any gamma ray run in combination with other cased-hole tool during well life, to evaluate changes in the top of proppants, creation of voids, as well as a preliminary inspection of zone producing sand after the well being produced, which give early information of sand production risk zone.

This paper demonstrates a simple method of using gamma ray to evaluate gravel packing qualitatively, time lapse monitoring as well as a preliminary warning of sand failure for multi zones gravel pack wells. The advantage of this method over existing tools is data can be obtained from any cased-hole gamma ray without dedicated run during well life.
Tiltmeter Hydraulic Fracturing Mapping on a Cluster of Horizontal Wells in a Tight Gas Reservoir
Authors: Zhou Jian , Zeng Yijin , Jiang Tingxue , Zhang Baoping , Zhang Xudong
Published: October 2015

This reservoir is a tight gas field and the target sand stone zones are generally staged fracturing treated at depths of roughly 1500 to 2800 meter. Knowing the direction or azimuth of the fracture orientation is important in development of this low permeability reservoir with horizontal wells. The paper presents surface tiltmeter hydraulic fracturing mapping results of 15 stages treatment in two horizontal wells at the same operational period. The two wells are part of a cluster of six horizontal wells located in North of Yulin, Shanxi province. Application of this technology is important in this tight gas field where fracture stimulation is a key method for production enhancement and reservoir development. This was the first deployment of tiltmeter mapping on a cluster of horizontal wells, and several modifications were made for the standard procedures. Using an array of 54 Surface Tiltmeters, the mapping was performed on all 15 treatments with the average perforation depths of TVD 2540 to 2545m at each horizontal section to determine hydraulic fracture azimuth and fracture length, respectively. For the first horizontal well R-3H, the tiltmeter mapping results show that, the azimuth of fractures is between N53 °E and N71 °E, and the fracture half length for stages fractures is between 112m and 149m. For the second horizontal well R-5H the tiltmeter mapping results show that, the azimuth of fractures is between N67 °E and N76 °E, and the fracture half length for stages fractures is between 107m and 142m. Besides, in the well R-3H from stage 7 to stage 9, the horizontal volume component of fractures, increased from 17% to 34%, as well as in the well R-5H from stage 5 to stage 9, the horizontal volume component of fractures significantly increased to 69% from 20%. Meanwhile, the production of the two wells after the fracturing was the first and second among the cluster of the six horizontal wells, respectively. Thus, by using the synchronous fracturing technology, we believe that it not only improved the complexity of the staged fractures between the two wells but also led to a better production enhancement.
Economic Comparison Between ESP and Rod Pump for Same Rate Wells
Authors: Pandit Akchay L. , Abdelaziz Issa Yasser , Khamis Mahmoud Bakr , Quttainah Riyad , Al-Ajmi Rakan N
Published: October 2015

In Oil Wells the design for each feasible artificial lift method is determined before running the economic analysis to better determine the efficiency of a particular installation. Consideration of the applicable artificial lift method helps to generate the necessary information for the net present value (NPV) analysis.

In this paper, a study is carried for economic comparison of the wells with same design production rate considering two artificial lift methods i.e., ESP (Electrical Submersible Pump) and rod pump. In order to increase the operational window in general, units with expected higher run life and robust construction are preferred. Therefore, in this paper firstly, it is discussed for rate comparison between conventional beam pump and unconventional extra-long stroke rod pumping units. Secondly, simulation result of ESP for the same production rate as is achievable by unconventional rod pumping unit is discussed and thirdly an economic comparison is carried between them. It will be clearly seen for the economic variation by production either through Unconventional rod pump or ESP lift method for same target rate and same pump setting depth.

To use the NPV comparison method, it is important to have a good idea of the associated costs for each system. This requires to evaluate each system carefully for the particular well and be aware of the advantages and disadvantages of each method and any additional equipment (i.e., additional costs) that may be required.

Therefore, in this paper comparison is carried for the operating expenses (OPEX) for two replacement choices—a smaller-size ESP and a long-stroke pumping unit, and its NPV. Comparative plots are obtained for rate Vs cost to generate NPV at different depths and corresponding rates. The results obtained is a valuable data base for economic comparison between ESP and rod pump for same rate wells.
Steam Injection Tracking System
Authors: Najaf Abdulaziz , Altarabulsi Khadhr , Taha Abdalla , Alsarraf Zahra
Published: October 2015

The state of Kuwait is developing its unconventional heavy oil fields. Currently, the Kuwait Oil Company KOC which is the national oil company of Kuwait is implementing a pilot project which utilizes the cyclic steam stimulation CSS Technology in accordance with different artificial lift methods to test the feasibility of applying the CSS technology in different areas of these fields. Moreover, it tests the effect of multiple steam cycles on wells and evaluates the performance of the wells with the selected artificial lift methods.

During the pilot stage, numerous numbers of data is being received daily from the well site. Integrating and analyzing these data manually requires huge efforts. Thus, a Steam Injection Tracking System is created to serve both management and operation sides by integrating all the well data including operational and financial parameters. The system will represent all these parameters graphically which helps the engineers to better understand the performance and economics of this pilot. This will be impacted for the best prediction of this pilot project and the unconventional fields' developments.

The results of implementing this system exceeded all expectations. It provided an excellent understanding and management for the pilot. On the management side, the main page of the software shows and summarizes automatically the historical and current status of each well in the pilot with its economics. Also, it helped in selecting the proper zone to utilize the CSS technology by showing the zones which responded profitably to that technology. On the other side which is related to the operational, it helped in selecting the proper well completion with its proper artificial lift method by presenting the historical production, expenditures, and profits. Moreover, it visualized all the essential daily well parameters such as steam quality, flow rate, and pressure readings associated with the occurrence of operational problems such as shutdowns and leaks. Finally, it allowed the engineers to style a customized sensitivity studies by graphing any parameter with respect to others.
Over Four Decades' Experience With Gas Dewatering at Naturally Fractured Gas Reservoirs in South-Sichuan, China, What Have We Learned?
Authors: Xueqing Tang
Published: October 2015

Early water breakthrough occurs frequently in naturally fractured gas reservoirs. To minimize the impact on gas production, gas dewatering technology has been applied successfully since 1969 in South-Sichuan gas sector, China. During past over 40 years, gas dewatering technology has been utilized in 326 naturally fractured gas pools, including pilot tests at individual wells and field wide applications in entire gas reservoirs at both initial geopressured and late pressure-depleted development phases, forming systematic and mature practices. This paper presents and analyzes five typical, innovative dewatering practices:

1). Water and gas production simultaneously from updip wells in massive gas reservoirs with weak edge water.

2). Gas production in updip wells while water production from downdip wells with strong bottom water drive.

3). Water and gas production simultaneously in downdip wells in geopressured formation below gas/water contact.

4). Combination of water/gas co-production in downdip wells near gas/water contact and pure gas production in updip wells

5). Newly drilled horizontal wells located below gas/water contact are used for water and gas co-production, in order to bring updip, prolific, and watered-out gas wells back production.

The results are that production decline trends in gas pools at different stages have been arrested and flattened out, offsetting previous double-digit decline. The best field case is plateau production rate sustained for eight years without additional drilling, with peak off-take rate of above 8%, relatively stabilized flowing wellhead pressures, gas flow rates and gas/water ratios. The paper also addresses some of the lessons learned and the criteria of the optimal practice for selecting and designing gas dewatering technology.
Subsea Field Development Optimization Using All Electric Controls as an Alternative to Conventional Electro-Hydraulic
Authors: Hasan Z. , Kapetanic N. , Vaughan J. , Robinson G. M.
Published: October 2015

This paper describes the overall aspects of an all-electric controls system using an eSolutions approach describing advantages of eSolutions over conventional control systems and associated challenges. Illustrations and conclusions are provided from technical evaluation studies for esolutions conducted for several applications globally. In addition, actual field experience of eSolution systems gained to date including installation, commissioning and operation is discussed.

Global oil and gas discoveries offshore are getting deeper with increased tieback distances. This is driving the development of all electric subsea production systems to enable extraction and transportation of hydrocarbons to the shore and or host facilities. At present, the oil & gas industry is predominantly using electro-hydraulic subsea control systems which are likely to continue as the system of choice for some time. The need for simpler and lighter subsea equipment will increase the opportunity to use all-electric subsea production control systems. Therefore it is important to understand how all electric control technology will impact performance, risks, costs and attractiveness of the subsea production system in the future. The advent of Subsea Processing and associated electrical power consumers on the seabed as well as the need for fast acting control systems is an enabler to have more electrical power available on the seabed for use.

Case studies including alternate field layouts with various step-out distances have been performed using an all-electric control system versus an as-built electro-hydraulic control system. Recommendations for all electric control system architecture and associated products required for the system were established from the performed studies. For eSolution system the subsea tree design was modified to use an electrically operated actuator, eSCM and removal of all controls tubing and compensator chests to allow comparison with an existing electro-hydraulic tree.

Benefits for eSolutions as related to simplification of assembly and test as well as fabrication will also be discussed.
An Electromagnetic Wave Based Water Cut Meter and the Influence Factors of Measuring Accuracy
Authors: Qinghai Yang , Xiaohan Pei , Fangchao Liu , Lianyu Wang , Jianwen Yan , Jinqi Wang
Published: October 2015

Most of oil fields in China have stepped in the development stage of high water cut. The accurate measurement of downhole water cut is the key to master the developing status, upon which injection and production adjustment could be implemented to improve oil recovery. This paper proposed an electromagnetic wave based water cut meter, which can realize full-range measurement of the water cut with high resolution and accuracy. The measuring sensor is equipped with two coaxial cylindrical conductors, the oil-water mixture flows between the two conductors during the measurement. When electromagnetic wave transmits in the coaxial sensor full of mixed fluid of water and oil, the wave phase shifts regularly. The water cut of the mixed fluid is calculated through the measured phase variation. Based on the analysis of polarization principle, dielectric property, transmission law, and the circuit implementation, this paper established the mathematical model of electromagnetic wave phase variation, and determined the frequency of electromagnetic wave. Then an electromagnetic wave based water cut meter was proposed. Through simulations and experiments, the paper studied the influence factors of measuring accuracy, including the mixed fluid's temperature, salinity, pollution to the conductors, and emulsive state. The temperature and salinity show associated effects on the measuring result. If the salinity is low, the response of water cut meter decreases with temperature rising. If the salinity is high, the response is just the opposite. Under different emulsive states, the response frequency of the mixed fluid exhibit same tendency, although the frequency value may show some difference. The oil films adhered to inner or outer conductor both give rise to measuring errors, while the pollution to the inner conductor produces more obvious influence. The response characteristics of water cut meter were also summarized in the paper and the compensation methods to eliminate or reduce the interference were confirmed. At present, in most cases, the downhole water cut are measured during well logging or separate-layer producer testing. This paper proposes an electromagnetic wave based water cut meter, which can be equipped in the downhole production regulator and realize automatic production adjusting.
Foam Hammers Enhanced the Performance of Hammer Drilling in Potential Water Formations
Authors: HU Gui , MENG Qinkun , LIU Xinyun , Tao Ye , WANG Xiangdong
Published: October 2015

Air hammer drilling technique has long been considered an effective approach to improve the rate of penetration (ROP) in hard formations. However, when being used in wet or water formations, air hammers are easy to output less energy or to be failure to work; in addition, the formation fluids would flow back into the gas chamber cylinder of air hammer when the gas circulation was stopped during the pipe connection time. In potential water formations, the operators would worry the possible failures of air hammers, thus quit the air hammer drilling technique and choose a comparatively safe drilling technique even with a lower ROP.

A kind of foam hammers was developed. It is suitable for both dry gas and wet gas (misted gas or foam) drilling media with high energy output compared to the air hammers. Furthermore, with the installation of anti-backflow device, the foam hammer can effectively seal the formation fluids and prevent their backflow into the gas chambers of hammer.

Two field tests were carried out. The lithology of the both cases’ targeting formations was hard rocks and the ROP was no more than 1.5 m/h in mud drilling. Air hammer drilling technique might be the best choice and the ROP might be increased by 5-10 times. However, due to the potential water strata contained, the operators had no confidence to employ air hammer drilling technique firstly. If the wet formations were encountered in advance with a short dry interval and needed to change to misted gas or foam drilling technology, an overwork of bit-change is needed and the short interval of gas drilling would not bring economical benefits. The foam hammer drilling technique can solve this problem. With the foam hammer, there was no need to trip out/in the BHA when changing into misted gas drilling or foam drilling due to the water formations. The results in two cases showed that the ROP of foam hammer in gas drilling medium was 5~10 times higher than traditional mud drilling, and the ROP in foam medium was 2~3 times higher than traditional mud drilling without reservoir fluids backflow into the hammer's gas chamber.

With the foam hammer, the operators may firstly apply the gas drilling technique in dry formations. If the encountered strata contain water, they can immediately transformed into wet gas drilling medium such as misted gas or foam with no tripping out/in to change the bits. Thus, improve the drilling performance compared to air hammer drilling.
Application of DOWS (Downhole Oil Water Separation) Technology Used in High Water-Cut Oilfield: Case Study
Authors: Yang Gao , He Liu , Feng Li , Yong Zhang , Bo Yu , Haoyu Lu
Published: October 2015

High water-cut is a common problem affecting oilfield stabilized production in the late period of oilfield development. Downhole oil water separation (DOWS) technology provides an effective way for the long-term economic development of high water-cut oilfield. DOWS can separate the oil and water in the wellbore directly with a hydrocyclone. The oil-rich stream is produced to the surface while the water stream is injected into the water-injection layer or abandoned layer. DOWS technology has made new developments in China as the progress of downhole date monitoring and control technique. The DOWS system consists of hydrocyclone, downhole date monitoring system, two pumps used for lifting and injection respectively. Hydrocyclone contour line was optimized and increased the separation efficiency to 98% or more. Date monitoring system includes flow meter and pressure gauge to surveil the flow and pressure of injection layer in real time. These dates can be transmitted to the ground through the cable and then to the remote terminal by GPRS modem. Engineers can monitor working situation of the DOWS system and control the separation effect using PC or mobile phone in the office. The inlet of hydrocyclone and the injection pump was designed to adapt to the limited space in 5½" casing well. This paper reports the characteristics of DOWS technology used in China and the latest advances we developed. This technology has been used in high water-cut blocks in Daqing Oilfield and Jidong Oilfield in China. Field tests show that DOWS technology can reduce the ground water production more than 75% and maintain the oil production unchanged in high water-cut oilfield. DOWS system has worked properly more than 400 days.
Electronic Control Separate Layer Flooding – A Case Study in Jilin Oil field
Authors: Lichen Zheng , Xiaohan Pei , He Liu , Dong Chen , Jiaqing Yu
Published: October 2015

Oil production from low-permeability oil reservoir plays a more and more important role in oil production. Separate layer waterflooding is an effective method in improving the oil recovery, but because of low adsorptivity of low-permeability reservoirs, single layer flow rate is too small to be measured accurately, the interlayer interference makes it more difficult to get right flooding rate, and the smaller water nozzle is easily blocked by contaminant.

A new electronic control water flooding technology is presented in this paper. Powered by DC battery, the system has a gear motor acting as adjustment element, flat nozzle as flush control, swing-rod flowmeter as test gauge, a pressure sensor installed behind nozzle to supervise the reservoir pressure, and a temperature sensor to supervise the downhole temperature. The whole system is controlled by microcomputer, realizing automatic calibrate of flow. Synchronous testing and adjusting process has been invented to eliminate the interlayer interference, and the nozzle will be opened fully periodically to let out the contaminant.

This new technology has been tested in Jilin Oilfield and proved to be effective. The swing-rod flowmeter can test small flow rate as low as 1.5m3/d, which can meet the requirement of low-permeability reservoir flooding. Synchronous testing and adjusting process has solved the interlayer interference problem and improved the testing and adjusting efficiency greatly, a testing and adjusting period can be finished in 5 minutes. The periodically opened nozzle solves the block problem and prevents the system from failure because of contaminants.

The new electronic control water flooding technology provides an effective way for low-permeability oilfield flooding. The newly invented swing-rod flowmeter has solved downhole flow measurement problem, and the synchronous testing and adjusting process has addressed the interlayer interference problem and improved the calibration efficiency greatly.
New Correlation for Predicting Asphaltene Deposition
Authors: Sulaimon A. A. , Govindasamy K.
Published: October 2015

Precipitation and deposition of hydrocarbon solids such as asphaltenes and wax are some of the major challenges facing the oil and gas processing and transportation industry. Deep-water, high pressure and high temperature (HPHT) environment are currently being explored for meeting the ever increasing energy demand and operating companies allocate huge resources annually to mitigate flow assurance problems. The aim of this study was to develop correlations for predicting asphaltene deposition tendency of crude oils since the experimental analyses are both laborious and capital intensive. SARA analyses and refractive index measurements were conducted on four Malaysian crude oil samples and the correlation development is based on the measured Collodal Instability Index (CII), the Refractive Index (RI), molecular weight of oil and the molecular weight of the lumped fraction of the crude oil.

Results from the mathematical correlations developed from the experimental data have proved reliable as predictions compare favourably well with the actual data. Analysis of the results show that the difference between the refractive index (RI) of the crude oil and the refractive index at the onset of asphaltene precipitation for the samples (∆RI) are less than 0.045 while the CII for the four crude oil samples A, B, C, and D are 1.09, 1.43, 5.64 and 5.83 respectively. These indicate that all the oils investigated have high tendency to precipitate asphaltene.
Validation of Drillpipe Rotation Hydraulics Using Drillpipe Eccentricity as a Key Factor
Authors: Hemphill Terry
Published: October 2015

The theoretical study of the calculation of pressure drop with and without drillpipe rotation was recently presented to the industry. In the study, fluid velocities, drilling fluid shear rates, and their corresponding shear stresses were used to model increases in annular hydraulics caused by drillpipe rotation in non-Newtonian fluid flow. No extra modifications (i.e., added exponents, multipliers, etc.) were used in the modeling of circulating shear rates.

It has been known for some time that the position of the drillpipe (in the annular center vs. off-center) has a significant effect on calculated pressure drop. Yet, most conventional pressure drop calculations neglect both drillpipe rotation speeds and drillpipe eccentricity and assume the drillpipe is always in the center of the annulus. It is known that moving the drillpipe from the center of the hole to an off-center position can reduce circulating annular pressure by up to 30%, and these reduced pressures can be increased significantly using increased drillpipe rotation speeds.

Validation of this purely theoretical approach is presented using available field fingerprinting information, where annular pressure changes with fluid velocity and drillpipe rotation speeds were measured using downhole pressure tools. Levels of equivalent circulating density (ECD) were calculated from the changes in pressure drop using standard equations. Hence, this kind of validation is quite different than what has been used previously, for which only some success was achieved in matching the data.

The results presented here show that small ranges in values of drillpipe eccentricity can describe the changes in measured pressure drop for the following: Vertical to near-vertical wellbores (one range set)Deviated wellbores (a second range set)

Using the small ranges in drillpipe eccentricity presented in this study, drilling engineers can better calculate the hydraulic effects of drillpipe rotation in a given drilling situation where no experimental fingerprinting data is available.