bluuebunny/crossref_metadata_2025_split huggingface dataset:
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

Abstract
Tremendous amounts of hydrocarbons are located in deeper formations, such as in Tarim basin of China, some reservoirs buried so deeply (&gt;7600m) that we experience higher temperature (&gt;180°C) and pressure (&gt;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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.