bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Role of Pressure Observation and Pressure Transient Analysis in Changing the Geological Concept of Mature Oil Field
Authors: Mukanov Adil , Aldazhar Aibek 
Published: October 2019

Abstract
The field of interest was discovered in late eightees. The main productive zone 1 obtained oil. The reservoir 2 is uplift basement located in the center of the field, to which reservoir 1 is pinched out and confined to reservoir 2 from east and west. The reservoir 1 has a gas cap and production is characterized by high GOR with no signs of any decline despite the long production period.
Therefore, all the available information of geology, production and pressure transient analysis were reviewed. There has been no production from the basement and just one well has been observing reservoir pressures for last ten years. These data were plotted bringing to unexpected result. The plot showed stable declining trend. So, there was a question – how does it happen when pressures are continuously decreasing while there is no production from the reservoir 2? Thus, gas sampling was performed on all three parts, pressure buildup and interference tests were conducted, geological data were reviewed and analyzed.
After completion of the works, the following results were obtained. PVT analysis indicates similar properties of gas from all three wells. However, the most important fact is that the results of interference test proved obvious pressure communication between wells in the reservoir 1 and 2. In addition, analysis of geological data also does not exclude the possibility of the communication. As the result, a conclusion that the two reservoirs could be one reservoir is drawn up. It is assumed that the main channels for interconnection are fractures, since the formation 2 is metamorphic reservoir with fracture network.
Reservoir pressure monitoring and pressure transient analysis became main factors and source of valuable information for changing the geological model of the field. Once again the importance of the pressure transient analysis is proved to be applicable not only by reservoir engineers but also by geologists. Eventually, the main results of the study influenced on the entire development strategy of the mature field.
Evaluation of Vertical Fracture Propagation Using Combined Spectral Noise Logging and High Precision Temperature Logging Data in a Low Permeability Sandstone Reservoir, Western Kaz
Authors: Yeleussinov Doszhan , Bekmagambetov Dinmukhammed , Crabb Ivan , Berdimuratov Alen , Nagimov Vener , Zhumekeshov Aman , Makashev Azamat , Makarov Dmitry 
Published: October 2019

Abstract
Hydrocarbon production from low permeability heterogeneous clastic reservoirs consisting of a sequence of thin, interbedded sand and shale laminations is challenging. Hydraulic fracturing is essential to achieve good production rates. An understanding of fracture geometry is very important for optimal reservoir management and development. This paper describes the application of an advanced logging system to evaluate near-wellbore vertical fracture properties.
Conventional production logging focusing primarily on wellbore flow geometry such as perforation and behind casing flow through poor cement may not adequately evaluate fracture properties due to a limited radius of investigation. To overcome this, a campaign using an advanced logging system containing spectral acoustic and high precision temperature measurements to evaluate near-wellbore fracture flow distribution was implemented. The main feature of this logging technique is the ability to scan the active flow behind the casing a few meters from the wellbore. The reservoir flow profile is assessed by temperature modelling enabling differentiation of the different flow regimes and inflow contributions.
Two vertical water injection wells hydraulically fractured into the low permeability clastic reservoir were logged. Vertical fracture geometry was precisely determined for each case and reservoir injection profile determined based on temperature modelling. Detailed pre-job modelling was necessary to define the logging program including optimal flowing and shut-in regimes. This enabled improved efficiency and accuracy when interpreting the results. The results enabled the determination of any out of zone injected volumes. This study revealed new insights in evaluating fracture geometry that can then be applied to reconcile post-job fracture modelling and improve reservoir management and water flood optimization.
The Heaviest and Longest 13 3/8 Full-String Casing Run in the Caspian Sea Region
Authors: Akbarli Elchin , ismayilov Elshan , Masalmah Mohammad 
Published: October 2019

Abstract
The Bulla gas-condensate reservoir is a high pressure and deep water reservoir which is located in the north-west site of Baku Archipelago. In the past 2 years, two wells have been drilled to the VIII horizon and have been delivered successfully to the client. While drilling Well 2, a 13 3/8" intermediate casing string was run to a depth of 5093m. It was registered as the heaviest and longest 13 3/8" full-string casing in the Caspian Sea region. The objective of this paper is to share the experience of running this intermediate casing string in the Bulla reservoir and to discuss how improved well design programs can reduce the cost significantly and eliminate well-related risks associated with two-stage casing running operations.
It is very complicated and challenging to run long section casings in one run, especially when accompanied with swelling shale geological formations. Furthermore, this was accompanied by extremely heavyweight and increased equivalent circulating density (ECD) and drag. The operation was pushing the boundaries of previous drilling operations in the Caspian Sea. However, the drilling contractor company managed to overcome all these challenges by using detailed engineering calculations and selecting the most appropriate rig configuration in advance. It was achieved by using conventional casing running operations along with advanced technologies and by applying the best practices to prevent further possible problems.
A 13 3/8" full-string casing was successfully run in the first well (Well 1) to a depth of 4938m, and in the second well (Well 2) to a depth of 5093m which were registered as new weight records for the Caspian Sea Region. Totally, 66 hours were needed to complete the running operations for the second Well. Usually, that casing string would be run in two stages using liner hanger and therefore, it would create technical complexity and difficulty. This technological complexity brings its own risks, compromises, and problems. By implementing engineering approaches, the two-stage casing running operation was substituted with a simpler and more effective design. The conventional casing running technique reduces the number of casing running operations, and the target depth was reached with the optimal and the most economic well construction design.
The results and conclusions of this paper will help well design engineers to simplify well construction, to use a smaller number of casing strings, and to reduce the risks and technological complexities associated with multi-stage casing running operations.
Cement Evaluation with New Generation Ultrasonic Tool in Multiple Casings Increases Operational Efficiency in Tengiz Field, Kazakhstan
Authors: Ayazov Zhalgasbek , Se Yegor , Timonin Andrey 
Published: October 2019

Abstract
Cement evaluation with wireline tools across two different casing sizes is cost-effective and time efficient, but also quite challenging. The acquired data quality, especially across the larger casing, is often affected by the tool eccentricity and poor signal-to-noise ratio due to severe attenuation of acoustic signal by the mud. New ultrasonic technology is required to acquire reliable data for cement evaluation, necessary to assure long-term well integrity and guide operational decision-making processes during well execution.
In this paper, authors discussed several case studies, where high quality cement bond data was acquired across both 7-inch liner and 9.875-inch casing in 17.3 ppg oil-based mud in a single wireline descent by using new generation ultrasonic transducers.
Drilling campaign in the Tengiz Field was restarted in 2012 and reached its peak in 2019. The majority of the wells in the new drilling campaign utilized fit-for-purpose (FFP) well design with long production casing section, which consisted of 9.875-inch casing to the top of the Kungurian Salt and a 7-inch × 7.25-inch liner to the top of the reservoir. Both sections required cement evaluation to guide operational decision-making processes and comply with regulatory requirements.
In the past, cement quality evaluation was performed with standard ultrasonic tool, logged across 7-inch liner and 9.875-inch casing in a single descent. However, heavy mud weight (17.3 ppg) required to drill the salt section caused strong attenuation of the acoustic signal, resulting in poor log quality and unreliable cement evaluation.
The new ultrasonic tool with new generation transducers was successfully introduced in several wells. Comparison of results for cement evaluation with standard and new generation ultrasonic tools showed significant improvement in data quality for both 7-inch and 9.875-inch tubulars in wells filled with 17.3 ppg oil-based muds. Acquired data allowed confident evaluation of cement quality, as well as assessment of the cement contamination level and casing centricity. Reliable cement evaluation expedited operational decisions and clearly identified existing issues. The findings from the cement evaluation supported changes in the cementing design, which led to improved well reliability and integrity. Moreover, cement evaluation in two casings in a single descent saves ~12 hours of rig time per well, enabling significant efficiency gain and cost savings from ongoing drilling operations.
This paper summarizes TCO experience with the use of new generation transducers for cement evaluation, compares results between standard and new generation transducers and provides examples how acquired cement evaluation data impacted operational decisions and cementing practices.
Water Shutoff Using Crosslinked Polymer Gels
Authors: Veliyev Elchin F. , Aliyev Azizagha A. , Guliyev Vugar V. , Naghiyeva Nurana V. 
Published: October 2019

Abstract
The study presents a new crosslinked gels composition for water shutoff operations. The rheological behavior, PSD of kernel solution, propagation capacity and obtained RF/RRF values regarding on bottomhole conditions have been examined. Obtained polymer composition showed high resistance to the 30000 ppm water salinity at 62° C. Three different polymer concentrations used in experiments demonstrates good correlation with obtained RRF values. Therefore, observed deviation in RF values was less than 15%. It’s explained with relatively low viscosities of kernel solution. It was determined critical concentration of crosslinker leading to viscosity reduction. Comparison of different gels in various salinity environments showed particle size dependence on salinity. However it was less than 10% and has no strong impact on RF/RRF values. The propagation experiments were conducted on 1000mD/500 mD sandpack models. Adsorption experiments carried out on ACG core samples.
Korolev Waterflood Pilot Completion Design for Water Supply and Injection Wells
Authors: Guest Roy , Dagistanova Kymbat , Bekishev Assylzhan , Playton Ted , Macias Ray , Fuller Micheal , Villegas Mauricio 
Published: October 2019

Abstract
The Korolev Field is located in western Kazakhstan where a waterflood pilot is planned in a sour naturally fractured carbonate reservoir. The completion design of the water supply and injection wells plays a key role in the economic oil recovery in a waterflood. An improper design can result in high cost, poor sweep efficiency, and low injectivity. This paper provides guidelines and technical studies on the completion designs for the Korolev Waterflood Pilot.
The process for selecting the completion design consists of field data acquisition, analysis, and a completion alternatives assessment. Injection data are acquired from a short-term injection test in the targeted reservoir. Core and fluid samples are acquired from the water source aquifer. The data are analyzed to determine the completion design parameters and objectives for the wells. Finally, the completion alternatives are assessed by a cross functional team through a method which determines an optimum design based on the completion objectives.
A summary of the key conclusions for the Korolev Waterflood Pilot completion designs are:Short-term injection test confirmed viable injection rates, operating pressures and the need for conformance control liner to improve the injection profile.Sand control is required in the lower completion of water supply wells to control solids production. The fines migration study provided key design information which allowed optimization of the water treatment facility design.The water supply wells preferred completion design is an open hole gravel pack with wire wrap screen.The water injection wells preferred completion design is a conformance control liner with swell packers and sliding sleeves.
This assessment is an effective approach for unlocking the hydrocarbon potential in harsh wellbore conditions for a waterflood project. Cost discipline, simplification and cross-functional team work are the key elements which resulted project cost savings and partner alignment on the design and execution plan.
Real-Time Gas Influx Analysis and Control in Managed Pressure Drilling
Authors: Ilin Andrew , Ameen Rostami Sayamik , Deshpande Kedar , Bukashkina Olga 
Published: October 2019

Abstract
Managed Pressure Drilling (MPD) usage have shown increasing demand in both offshore and onshore market especially for wells with narrow drilling margins. MPD due to its inherent ability to maintain desired constant bottom-hole pressure (BHP) is a clear choice when mitigating gas influx while drilling thus increasing safety and reducing non-productive time.
MPD removes pore / fracture pressure uncertainties by measuring the drilling window on real time. An enhanced hydraulics modeling that accounts for change in downhole conditions such as temperature, compressibility is key component for successful MPD operations to alter the surface back pressure (SBP) to maintain desired BHP. Aside from enhanced hydraulics model for BHP estimation, an accurate prediction of the gas influx propagation from the bit to the surface is critical for managing BHP dynamically while circulating influx out of annulus.
This work underscores development and usage of advanced multi-phase model to simulate gas influx transport and its effects on BHP during MPD operations. This work elucidates recent advances in the gas influx modeling, specifically single bubble model and kinematic two-phase model formulations are discussed in detail. The results of the single bubble model and two-phase model are compared using industry accepted software during gas influx control and circulation out of the well.
Record-Breaking ERD Intelligent Completion System Installations in the North Caspian Sea: Challenges, Solutions and Multi-Disciplinary Approach
Authors: Novokshenov Stanislav , Kosset Talgat , Goura Nicholas , Niverchuk Andrey , Letchikova Lidia , Nabiullin Renat , Dadashev Afrand , Nabokin Roman 
Published: October 2019

Abstract
In order to maximize oil recovery from shallow and thin reservoirs, Extended Reach (ER) producer and injector wells are becoming common in the Russian Sector of the Caspian Sea. In recent years, Korchagina wells have illustrated the difficulty of achieving effective production along lengthy reservoirs with traditional completion methods. The objective of this paper is to share practical experience gained during deployment of the most advanced Intelligent Completion Systems (ICS) in ER wells. The paper covers detailed analysis, challenges encountered, solutions implemented, and lessons-learned while completing multi-zone wells.
Hydraulically actuated ICS installations on the Korchagina field began in 2014 and continues to date, exceeding expectations for oil recovery. The paper discusses the deployment of recent record-breaking fully-electrically operated ICS in complex 3-D ER wells. Also, the paper covers the multi-disciplinary approach in optimizing drilling practices and techniques, which allowed landing of the longest 10¾" horizontal production casing at 3873m on Well A, as well as the deployment of the longest combined 7" × 5½" liner with wire-wrapped screens and a total length of 3447m, and the longest intelligent completion system with a total length of 3083m, on Well B in the Caspian Sea. The previous world record was comfortably surpassed, with deployment of the ICS inside the 7" liner to a depth of 5187m.
The detailed torque and drag (T&D) modelling of the liner and completion deployment was performed both at the planning and execution stages to ensure that there was sufficient surface weight and torque available. Proprietary Drilling Engineering software was used to derive the expected T&D, extract expected running conditions from previously executed wells, and predict potential challenges. It was also applied during the actual deployment with real-time data being extensively processed and analyzed. The slightly conservative modelling enabled identification of liner and ICS equipment that required modifications and helped to enhance running procedures. Further, the strategic approach to the placement of both swellable open hole packers for the liner, based on caliper and LWD data, and hydraulically-set inner-string isolation packers, is described.
The design and planning of the complete cycle of well construction, including deployment of the intelligent completion system, resulted in flawless completion of the wells with a successful field application and delivered a significant oil recovery increase on the field.
Auto Gas Lift Application in Azeri-Chirag-Gunashli Field, Azerbaijan, Caspian Offshore
Authors: Huseynzade Samir , Hammond Charlie , Pashayev Ahad , Allahverdiyev Ilkin , Mollayev Rovshan 
Published: October 2019

Abstract
The Chirag platform is one of six BP operated platforms to produce from the Azeri-Chirag-Gunashli Field in the Azerbaijan sector of Caspian Sea. The Chirag platform was scheduled for early oil delivery but was not developed with any means of artificial lift and as the field became mature, wells experienced water-breakthrough. In the absence of artificial lift, wells can typically flow naturally up to 20-40% watercut at steady-state conditions, however restart of these wells is challenging and at some point, impossible.
Historically high watercut (20-40% and above) Chirag wells were side-tracked to up-dip dry oil leg. However, sidetracking for this reason could be uneconomical and could leave reserves from main production sands unrecovered. Therefore, enabling artificial lift for Chirag wells is vital. Several artificial lift options were evaluated, including ESPs and Jet Pumps. The most attractive method proved to be Gas-lift. In the absence of surface facilities to provide gas lift injection into the wells, using high pressure shallow gas formation as a source for gas lift was identified as suitable both from technical and economical perspective. This project was the first of its kind implementation in BP and offshore Caspian. A number of technical challenges had to be solved to deliver the project: Selection of continuous and permeable gas bearing formationOptimum gas lift valve size selectionSand production from perforated shallow gas formationPlant constraints to start-up and produce the well with AGL
Three formations were selected as a potential energy source for gas-lift supply. It was identified that among all three zones only one is continuous (confirmed by reservoir pressure data in the Chirag area), with a good rock properties and adjacent to a field operated by the National oil company SOCAR with long production history. The gas lift valve size was selected to deliver enough energy to continue producing the well at high WC (&gt;40%), minimize depletion in gas formation and lessen shut-in cross-flow of the lift gas. Perforation and down-hole completion were designed to minimize likelihood of sand production from gas formation, and in the case of sand production limit erosion of downhole equipment. Thorough risk evaluations were carried out to enable start-up of the well with high shut-in tubing head pressure which was due to high reservoir pressure of gas formation and its cross-flow to main production sands.
This paper will focus on describing the technical evaluations carried out to assess and solve the challenges presented above and compare current performance of the wells' vs predicted. As of today, two Chirag wells are operated with AGL and one well has AGL capability for future implementation. The AGL project is confirmed to be a reliable mean of artificial lift method for Chirag wells assuming limited depletion in shallow gas reservoir.
Hybrid Swell Packer - Water Prone Zone Isolation
Authors: Ma Shian Ee , Bt M. Zain Siti Nur , B. Ishak M. Faizatulizuddin , B. Omar M. Afiefe , Chin Pui Ling Jennie 
Published: October 2019

Abstract
Conventionally, for an oil development field with the risk of water breakthrough during its life time of production, a cased hole with perforation method will usually be chosen. This is a proven method of completion strategy that enable an effective way to provide proper water isolation.
Project B is an oil development project in Malaysia with 3 wells in total, which were drilled and completed by early February 2019. During the early stage of the project at Front End Planning, offset well data suggested that there are 2 target zones of hydrocarbon in the field being separated by a thin layer of shale (3meters), dividing them into upper and lower lobe of oil reservoir. It was expected to see a water reservoir below these two reservoirs and hence, the proposed completion strategy was to perform Cased Hole with Perforation and Gravel Pack. Further studies between Production technology and Completion team had raised the concern on the integrity on the water isolation due to the shunt tube system used for the gravel pack job.
To effectively isolate cross flow between the upper and lower lobe of the oil zone and delay the water break through from the lower water reservoir section, project team modified the completion strategy from Cased Hole Gravel Pack to Open Hole with Stand-Alone Screen (OHSAS). Hybrid Swell Packers will be installed at the thin shake layer to provide the zonal isolation.
The completion strategy modification had simplified not only the offshore completion operation, but also the logistic planning and footprint allocation due to lesser equipment required. Total cost saving had been achieved at USD 1.44 Milliom with around 2.4 days reduction on completion operation timing.
This paper will discuss the rational to modify completion strategy, cost comparison and operational sequence between these 2 methods of completion. This paper will also cover the challenges, limitation to deliver the well.