bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimize Development Strategy of Upper Burgan Reservoir Through Multilateral Well with Inflow Control Device in Raudhatain Field, North Kuwait
Authors: Chowdhuri Sankar , Cameron Peter , Gawwad Tarek A. , Madar Mohammad R. , Sharma Siddhartha Sankar , AlMutairi Moute'a Dughaim , Rajagopalan Vijay Shankar , Chellappan Suresh , Al-Ajmi Moudi Fahad 
Published: October 2015

AbstractDevelopment in drilling technology allows horizontal and multilateral wells to increase hydrocarbon recovery and accelerate production from high water mobile reservoir by increasing the reservoir contact surface. In coning situations, such as production of oil reservoir with a bottom aquifer, multilateral wells reduce the coning affect and hence prove to be more cost effective. To address these challenges, first multilateral well with Level-4 junction combined with Inflow Control Device (ICD) was planned, designed and drilled in Upper Burgan Reservoir of Raudhatain Field, North Kuwait.The Upper Burgan Formation is layered sandstone–shale sequence deposited in deltaic settings having very fine to fine grained marine influenced channel sand as reservoir rock. Geosteering and evaluating these wells is very challenging without using a proper LWD technology. Indeed, the resistivity anisotropy is a major issue, especially if it occurs with influence of other bed boundary effects like resistivity of adjacent beds or polarization horn effects. Water coning issues in the field makes it even worse to interpret the resistivity data as they become spiky. To overcome these challenges the drilling bottom hole assembly was designed in the way to include the distance to boundary and the new Multi-function LWD sourceless technology. The capture gamma ray spectroscopy and formation sigma in real time has improved the petrophysical evaluation of this complex resistivity environment with mixed lithology in wells that are difficult or even costly to consider TLC wireline logging.The Lower Lateral of 2145′ with 8½" hole diameter was drilled through very fine grained sandstone in UB3 Lower zone and completed with 5" open hole ICD. The Upper Lateral of 1757′ was placed in UB3 upper zone having very good reservoir quality. This lateral was completed by 4½" open hole ICD. The production is comingled as the pressure difference between the two laterals was not more than 100 psi. The well operated under Electrical Submersible Pump (ESP) produced more than the estimated rate of oil during initial production.The success of the well not only addressed the issues related to enhancement of oil production and premature water break through but also opens up a new chapter of drilling multilateral wells in coming days in Raudhatain Field, North Kuwait. The paper covers the main challenges while well placement during geosteering to stay in the best quality of reservoir rock in structural and depositional complex settings and with the smart completion design for increase oil production and rate of recovery.
IOR/EOR Monitoring Onshore with Frequent Time-Lapse Seismic
Authors: Lopez J. L. , Przybysz-Jarnut J. K. , Hornman J. C. , Mateeva A.. , Zwaan M.. , Potters H.. 
Published: October 2015

AbstractWith the recognized cost and complexity of IOR and EOR projects onshore, there is a significant risk of projects not meeting their NPV or production targets, unless cost-effective well and reservoir management plans are in place to mitigate such risks. Time-lapse seismic could provide important and timely information to diagnose and remediate areal conformance issues, if the time-lapse data is of high enough quality and low enough cost to be acquired on a frequent basis. We review the business case, expected value, and affordability of seismic monitoring in IOR/EOR projects and the new technologies that may be used for this purpose. We illustrate these ideas with a case study from the Peace River heavy oil field in Canada, as it is implemented today to monitor steam injection in a relatively shallow reservoir and how it could be implemented in the future to reduce cost and preserve value by judicious adjustment of the frequency of seismic monitoring. We also comment on the challenges and technology options for monitoring of deeper reservoirs.
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.
Laboratory Study on Steam and Nitrogen Co-injection for Mid-deep Heavy Oil Reservoirs
Authors: Wang Cheng , Zhong Liguo , Li Jianping , Chen Gang , Zang Ye , Wei Fang 
Published: October 2015

Abstract
Surface steam injection is the most common enhanced oil recovery (EOR) technology used in heavy oil production. Nevertheless, limits exist due to heat loss for deep reservoirs. In the process of steam injection, adding a certain amount of nitrogen, which can reduce heat loss, maintain formation pressure and expand steam chamber, can effectively improve the development efficiency of steam injection.
In this research, high-temperature-pressure pressure/volume/temperature (PVT) measurements and sand pack flooding experiments have been operated for heavy oil of the target reservoir in Bohai Oilfield, China, observing effect of nitrogen on property of heavy oil and steam and nitrogen co-injection on displacement efficiency and optimizing gas-water ratio during the co-injection.
The results of PVT measurements indicate that the change of heavy oil viscosity is complex with the varying amount nitrogen dissolved. The reason is that dissolved nitrogen can reduce heavy oil viscosity on one hand; on the other hand, nitrogen can compress oil increasing its viscosity. The viscosity of heavy oil with dissolved nitrogen decreases significantly under low temperature and pressure (80°C, 15MPa), and the maximum viscosity reduction rate is 28%. Along with increase in temperature and pressure (150°C, 25MPa), the viscosity reducing effect becomes worse, especially at 150°C, the viscosity of heavy oil with dissolved nitrogen increases, on the contrary.
The results of sand pack flooding experiments reveal that adding nitrogen during stream injection can improve oil displacement efficiency significantly. However, the increase of oil displacement efficiency is different with the varying gas water ratio; therefore, optimizing gas water ratio has a great influence on displacement effect in steam-nitrogen co-injection process. There is an optimal gas water ratio in the process, which is correlated with temperature. For example, the optimal gas water ratio is around 50 and 100 respectively while temperature of 200°C and 300°C.
The key of mid-deep heavy oil reservoirs development using steam-nitrogen co-injection technology is gas water ratio optimization, and while optimizing gas water ratio properties of heavy oil, formation conditions and injection conditions, and many other factors should be taken into account. This research provides a direction to choose the optimal gas water ratio in the steam-nitrogen co-injection process.
Piloting Wireline Coring Technology in Challenging Unconsolidated Lower Fars Heavy Oil Reservoir, Kuwait
Authors: Mukherjee P.. , Al-Bader M.. , Peres J.. , Al-Matar B. S. , Kumar P.. , Choudhary P. K. , Al-Khamees W. K. , Stockwell M.. 
Published: October 2015

AbstractCoring reservoir rock has been an integral part of any oil & gas operator. With a vertically stacked multiple reservoirs in Kuwait stratigraphy cores are thus taken in various depth ranges from few hundred feet to higher than ten thousand feet. Wireline Coring technology, which has been successfully applied in various parts of the world, was found to be an alternative to cut down on rig time and maintain good quality of cores. Heavy oil shallow unconsolidated reservoir of Lower Fars was chosen to be tested with this innovative technology. This reservoir is as it is challenging for coring due to its highly unconsolidated nature with high intergranular porosity coupled with the issue of gravity settling of heavy oil which limits the individual core intervals.The CorionExpress® technology of NOV uses a PDC core bit which has a wireline- conveyed drilling insert to convert the core bit to drilling mode in matter of minutes. This helps in taking multiple cores with intermittent drilling without the need to take the string out. 140' of core was cut in continuous runs with drilling of intermediate shale and drilling to the final depth of the well successfully without any need to take the assembly out of hole. There was substantial time saving of about 30% in rig operation for coring and drilling even in this shallow reservoir where normal tripping time is much less. Recovery percentage was satisfactory considering the technology was applied without a huge advantage of past experiences and lessons for the conventional coring for the same reservoir.Gaps and lessons learnt indicated further scope to streamline the catcher and bit design for better recovery. It also requires rethink on operating procedures particularly in wireline rig up & rig down and core handling rig up & rig down for time saving. However, each of these factors need to be tailor made to the reservoir quality that is to be cored. This paper illustrates the thoughtful mix of technology, innovative techniques and proper coordination by aligning all concerned has helped in meeting the challenge of coring unconsolidated sand and it's processing to deliver a geologically acceptable core for laboratory studies.
Innovative Use of Mixer Design for Efficient Brine and Produced Water Handling
Authors: McPherson R.. , Sabey J.. 
Published: October 2015

Abstract
Through years of research and development, ProSep has brought to market a family of mixers for use in practically every application where separation of phases or constituents take place. In produced water applications, ProSep has incorporated a series of modulating mixers along with another proprietary process technology, the CTour Process, to provide a compact solution for new build as well as retrofit / debottlenecking applications. The CTour Process is the injection of natural gas condensates into the produced water treatment line for an in-situ extraction of residual OIW. The ProSep series of modulating mixers, along with our series of chemical injection mixers, provide the efficient mixing needed to achieve low sheer, homogenous fluid mixing of the condensate to aid to the extraction of PAH molecules and dissolved BTEX components as well as dispersed hydrocarbons. The modulating feature of the mixer allows for a maintained and consistent low differential pressure under varying flow rate conditions.
This same mixer technology can also be applied on the crude oil treating pipeline using our ProMix – for chemical injection of de-emulsifiers, corrosion inhibitors, and scale inhibitors – and ProSalt – wash water injection mixer – products. Both mixing systems allow for cost savings with regard to chemical and wash water usage and injection. Additionally, the homogenous mixes created allow for more efficient downstream process equipment, such as dehydrators and desalters, with less oil reporting to the brine water effluent, therefore reducing the burden on other separating technologies in the process. These unique designs offer efficient mixing over high turndown due to their ability to modulate, require less pressure differential for operation, provide a more homogenous mixture over a shorter distance, and provide a narrower droplet distribution curve.
Extending the Vitality of a Mature Oilfield Using Well Placement Technology: A Case History of 10 Years Innovation and Commitment, Junggar Basin Northwest China
Authors: Yang Kun , Du Hongling , Zhang Yi , Huang Lei , Zeng Yanqiang , Wu Congwen , Lin Xin , Kok Jeffrey , Wang Dahai , Wang Yong , Koon Lee Tow 
Published: October 2015

AbstractLuliang oilfield has been in production since 2001 and was originally developed from vertical wells. To arrest production decline, operators embarked on a horizontal drilling campaign in 2006 to achieve ultimate field recovery from remaining oil. A proper geosolution to optimize reservoir exposure while maximizing distance from bottom and edge-water was recognized as the key for success in this field.From 2006 to 2015, the 10 years of field development was sustained through a close collaboration between the operator and service provider. However, production reviews indicate that the Luliang oilfield is approaching the end of its field life as the main underground reserve is drained away. As this mature oilfield becomes increasingly difficult to develop, well placement technologies become increasingly critical along with the commitment to service quality. With the challenge increasing, the well placement strategy and solutions must be reformed as well. Innovative use of well placement technology and workflows are crucial to ensure service quality while balancing drilling costs within the margin of economics.From 2006 to 2014, a total of 200 horizontal wells were successfully constructed, achieving net-to-gross over 94% and improving the field's recovery efficiency by over 96%. Both productivity and cumulative production of horizontal wells were significantly enhanced compared to the original objectives. In 2015, 14 horizontal wells are on going; thus, after 10 years, the extension of this mature field's vitality continuous to press on.
Water Analysis - A Key Tool for Reservoir Monitoring Under Cyclic Steam Stimulation
Authors: Jain Anil Kumar , Ahmed Khalid , Ortiz-volcan Jose L. , Al-Khamees Waleed 
Published: October 2015

Abstract
During the process of Cyclic Steam Stimulation (CSS) variations in reservoir pressure and temperature occur changing the solubility of reservoir rock minerals in the formation water and therefore during production phase, produced water brings valuable information about dynamic characteristics of reservoir rock and fluid. Its analysis may provide an invaluable means for monitoring the reservoir. This paper describes the process of water analysis where results are interpreted on the basis of the principle that the solubility of minerals varies with change in pressure and temperature. This also shows the importance of water analysis as a key tool for reservoir monitoring in fields undergoing cyclic steam stimulation.
Water analysis is also used to optimize impact of produced water on Capex and Opex of oil production as water is required to be handled and disposed without impacting the environment, and is applied as troubleshooting tool to identify well problems and to validate log interpretations.
Field examples illustrate application of water analysis in i) mineralogical changes that takes place during CCS operation for reservoir monitoring and impact of steam on clays, ii) determining compatibility of injected steam with the formation water and compatibility of effluent with the formation water of disposal well, iii) surface facility design and water treatment before steam generation, iv) reservoir description and computing fluid saturation using resistivity of formation water and v) troubleshooting well problems, e.g. unanticipated water production because of channeling behind the casing and communication between the layers.
Paper discusses the importance of water analysis at each stage of CSS operation and its application in reservoir monitoring and describes field experience with water analysis in the surveillance of a CSS project.
Evaluation of Surge Protection Systems to Enhance Bunker Loading Rates to Ships
Authors: Mathew Benny 
Published: October 2015

Abstract
Offshore Oil export, being a batch process, is required to be at the highest loading rate possible to lift off the continuously produced oil and also to shorten the loading period of ships, so as to improve the time to market. But at the same time, it needs to be managed in the safest manner, as any operational error or a bad weather could cause a big oil spillage and pollute the marine environment significantly. This calls for a bigger offshore infrastructure, with large size and lengthy submarine pipelines all the way to the deep draft area of the sea to enable bigger ship to berth and a higher pumping rate with fail safe control system.
KOC started offshore crude oil export in year 1969, with the commissioning of Sea Island terminal located 10 miles offshore. It had a 48″ dia. Crude oil Submarine line and a 20″ bunker submarine line. The control system for emergency shutdown was provided with a surge relief system and a relief collection vessel at the sea Island platform. After 10 years, in 1979, a new single point mooring (SPM) terminal was added with surge relief collection vessels and the submarine lines were extended from Sea Island further 3KMs to connect with SPM. In year 1996, two new single buoy moorings (SBMs) were built and the same old submarine line was further extended 3 KMs each to connect with both SBMs. In year 2008, the complete offshore system was re-built with new offshore infrastructure as detailed under.
The present new offshore infrastructure consists of four (4) nos. of single buoy moorings (SBMs) of catering anchor leg mooring (CALM) type, each with a dedicated 56" dia. submarine pipeline of length over 20KMs, so as to cater the biggest range of oil tankers in the world. The crude oil loading rate could be over 100,000 bbls/hr simultaneously in each of the four CALM buoys. For bunker service to the crude oil ships, a bunker loading system consisting 20″ & 24″ submarine pipelines are also in place, to meet a maximum loading rate of 1000 Mt/hr for fueling the ship. The offshore loading terminal of SBM type, is a floating buoy without any permanent structure and is remotely controlled from an on-shore control room. The ship is moored to the buoy on a single point, so that it could move- weathervane - around the terminal. In the event of ship moving away from the terminal due to very bad weather or any other reasons, the crude/ bunker loading to the ship would be stopped automatically by a breakaway mechanism on the hoses. This would result in high surge pressure in the loading system and the weakest link, which is the loading hose, would be protected by isolating the same from the upstream by sudden automatic closing subsea valve (PLEM) together with emergency shutting of on-shore export pump.
Heavy Crude Oil Sampling and Assay For Refinery Capacity Planning: Design, Plan and Execution In A Supergiant Green Field
Authors: Ortiz-Volcan J. L. , Ghouti R.. , Al-Naqi A. M. , Jain A. K. 
Published: October 2015

Abstract
Assessing heavy oil composition of a green field, with an accepted level of uncertainty so it can be used for refinery capacity planning is a critical challenge. Knowledge of heavy crude oil properties is vital to understand potential adverse impact on process performance and total costs of the whole value chain, downstream (corrosion, catalyst deactivation, fouling and pumping) and upstream (corrosion, fouling, obstruction, producibility, lifting, pumping and transportation).
The usefulness of heavy oil properties is highly dependent upon how samples are representing the bulk of hydrocarbon resources that will be developed and the reliability of the sampling procedure which becomes even more challenging when performed in a geologically complex, multilayered, supergiant green field with wide variations of fluid properties vertically and aerially.
In this paper we present a field case with the methodology used to design, plan and execute a heavy oil sampling and essay for refinery capacity planning and the lessons learned, in an area of the field representing the first phase of development, in a supergiant heavy oil green field located in north of Kuwait.
This heavy oil sampling and essay was planned and executed under high levels of uncertainty, using previous crude assays, PVT data from appraisal and thermal pilot wells and reservoir static and dynamic model. Extensive statistical analysis was applied to understand and map uncertainties related to sampling, completeness and representativeness of laboratory tests vs. accepted international standards. The methodology was applied by a multidisciplinary project team involving specialists from upstream and downstream who performed the work using project management tools to design and implement the execution of sampling in the field. The project took near one year to complete and results are now used for refinery capacity planning at short and midterm. Lessons learned were documented so the future sampling and assays can be improved as data from more wells is going to be available during execution of development phase.