bluuebunny/crossref_metadata_2025_split huggingface dataset:
Production Optimization for Progressive Cavity Pumps by Interconnecting a Steady-State Flow Simulator and a Black Oil Reservoir Model through Integrated Asset Management Software
Authors: Ali Maaz , Salinas Veronica , Cui Shihao 
Published: October 2018

Abstract
At a time when oilfield economics call for the most optimized strategies to produce a field or set of wells, reservoir understanding and artificial lift technologies merge as one combined solution to provide top-of-the-class analyses for optimized production and economic success for very challenging projects. One of the most critical aspects related to the economics of the production life cycle is the maximization of net present value (NPV). This becomes even more relevant for wells that have high capital investment and expensive operating costs.
The objective of this paper is to describe the simulation workflow developed to integrate the interactive response of the reservoir as a response to the drawdown induced when artificial lift is placed within a well. Based on the reservoir response, artificial lift operational parameters can be adjusted at each step to maximize the total NPV for a group of wells in a field located in the Middle East. Sample data describes a case of five wells connected to the same facility and completed with progressing cavity pumps (PCPs).
The individual wellbores containing the PCPs were simulated using a steady-state multiphase flow simulator. Single-well models were used to feed the surface network model with flow lines, chokes and a separator. At the reservoir level, a reservoir model for each well was created using a black oil simulator. The use of an integrated asset modeler enabled automated interaction among single models, network model and reservoir models, allowing the creation of an optimization workflow. The integrated asset management software optimized PCP speed for each of the five wellbores to maximize oil recovery, delay water onset and maximize NPV of the field for one year. The optimizer also had to consider several constraints at both the wellbore and surface facility level. Minimum bottomhole pressures needed to be maintained throughout the simulation to prevent the reservoir from depleting prematurely. Water production also had to be limited to match surface handling capacities. Finally, PCPs needed to be constrained based on a maximum operating speed and maximum horsepower consumption.
The workflow created effectively integrated reservoir modeling with artificial lift performance to deliver an optimized operational sequence for the case study, presenting as results PCP speeds and NPV per month. The results of the simulation showed the potential to increase the NPV and oil production by 10.5% and 9.5% respectively. Furthermore, the current workflow is flexible enough to be extended to other forms of artificial lift and has the potential to fully optimize and evaluate complete fields.
SRP Equipment Customization Creating Value by Increasing Run Life in a Low Oil Price Environment
Authors: Hoy M.. , Kometer B.. , Bürßner P.. , Puscalau G.. , Eder S.. 
Published: October 2018

Abstract
This paper describes the measures undertaken to increase the run life of sucker rod pump (SRP) installations in the past five years in OMV Austria. Around 500 wells are currently operated with SRPs with an average water cut of 95%. Recurrent pump failures, caused by corrosion, mechanical wear, gas and sand production, significantly contribute to the operating expenditures of a mature oil field operator.
In the current low oil price environment the key strategy for economic oil production is seen in efficient low cost production optimization of the subsurface pump equipment. The primary objective was to reduce the life cycle cost (LCC) and deferred production - however, also the increase of production efficiency is an appreciated secondary effect.
Consequently, the failure analysis was completely revised and historic data was fed into a new database. A new process was implemented - starting with equipment details, determination of both failure cause and reason and resulting in a ranking for a detailed root cause analysis.
The results obtained from the failure analysis led to a profound understanding and rendered a prioritization of necessary actions possible. The optimization measures include design modifications, a stricter quality assurance of new pumps, material upgrades and special pump parts for the respective production environment. In addition an economic assessment of the LCC was conducted in order to quantify the cost impact of pump optimization.
The new failure statistic highlights the importance of certain failure modes. Accordingly the necessary pump upgrades were ranked, analyzed and successively executed. The continuous study already shows a change of failure proportions and furthermore improved the in-house knowledge.
Even though deploying SRPs for more than 60 years, a structured failure analysis led to new insights of material weaknesses. The introduction of non-API special parts allowed the customization of standard pumps in order to fit to the actual production environment and significantly enlarged the application area of SRPs. In-house material technology center and research laboratory offered valuable information for the root cause analysis. This created the basis for a stricter material specification than demanded by the API 11AX to avoid recurrent systematic failures.
Life-of-Well Gas Lift Installations for Unconventional Resources
Authors: Latif Bilal , McKenzie K. S. , Rodgers W. M , Stephenson G. B. , Wildman S. L. 
Published: October 2018

Abstract
In unconventional shale plays, the production profile varies dramatically within an extremely short period of time. Wells often produce at extremely high rates when initially completed and deplete rapidly before reaching production plateaus. This rapidly changing production profile presents a significant challenge to engineers designing artificial lift systems. Because of the method's flexibility and tolerance to a variety of producing conditions, gas lift has become a popular artificial lift choice in these wells.
To achieve optimal system performance, engineers often design gas lift installations to produce up the casing early in the well's life. This configuration minimizes pressure losses in the production string, enabling deep injection, improved drawdown, and higher flow rates. As the wells deplete and the production rates decline, the wells must be converted to tubing flow to ensure well stability. As the wells further deplete, they are often converted to intermittent gas lift. Unfortunately, it is not feasible to produce wells with tubing flow gas lift or intermittent gas lift with the typical downhole equipment configuration used in annulus flow wells. Therefore, transitioning to these late-life artificial lift configurations has required a workover rig.
A novel downhole equipment configuration was developed to eliminate the need for a workover rig when transitioning from annulus flow to tubing flow gas lift. Side-pocket mandrels with a special pocket porting configuration were selected to enable annulus flow with enhanced gas passage early in the well's life. To transition from annulus flow to tubing flow, the slickline-retrievable valves were pulled and replaced with reverse-flow gas lift valves. A field trial was conducted to demonstrate and test this completion concept. While more investigation is required to justify full field implementation, the initial results have been promising.
This project demonstrated that it is feasible to produce wells in annulus flow, tubing flow, and even intermittent gas lift with a single completion using readily available, off-the-shelf artificial lift equipment.
Acquisition of Downhole Pressures without Downhole Gauges in the Gulf of Thailand via the Self-Powered Intelligent Data Retriever
Authors: Pattarachupong Wiwat , Piyakunkiat Nuttapon , Ananwattanasuk Thongchai , Sirirattanachatchawan Thum , Sompopsart Suwin , Toempromraj Wararit , Koseluk David , Finley Douglas , Redman Michael , Wattanasuwankorn Reawat 
Published: October 2018

Abstract
Bottomhole pressure is one of the most important sources of data used to determine reservoir characteristics. By analyzing the manner in which bottomhole pressures change with time and flow rate, properties can be derived such as permeability, skin, boundaries, and reservoir pressure, which can enable the evaluation of hydrocarbon reserves and make economically feasible decisions. Downhole pressure data in production wells are most commonly acquired by running downhole pressure gauges on slickline into the wellbore. However, in offshore wells in remote locations, there can be major deterrents to capturing bottomhole pressures using slickline. Examples of these limitations include equipment and manpower availability, crane functionality, and offshore accommodations. Furthermore, there can be physical limitations to data acquisition from the presence of sour gas, high bottomhole temperatures, high wellbore deviation, or mechanical obstructions that can prevent the use of downhole gauges in the well. This paper presents an innovative method for acquiring the needed bottomhole pressures in production wells when traditionally used methods may present challenges.
An operator in the Gulf of Thailand wanted to obtain downhole pressures on their production wells but did not wish to run slickline and downhole gauges because of the concerns specified above. A new self-powered intelligent data-retriever system was suggested to the operator as it offered a method that could derive accurate bottomhole pressures without running downhole gauges. The new system consists of a high accuracy, high resolution pressure gauge and a companion bottomhole pressure conversion algorithm. The pressure gauge is installed on the wellhead and captures high-frequency surface-pressure data. The conversion algorithm uses the surface pressure data, along with wellbore information, and fluid properties to calculate downhole pressures.
The results of a series of tests with the self-powered intelligent data-retriever system demonstrated that the system can provide accurate bottomhole pressure results in production wells. These facts will be verified by the test results as well as the case history, both of which will be presented in this paper.
This technology was designed to reduce the cost of capturing downhole pressure data, lessen many of the logistical concerns that could occur when using traditional systems, eliminate the risks of a downhole gauge getting stuck in the wellbore, and acquire necessary data when downhole environments are corrosive.
A New Fatigue Management Workflow for BHA Integrity Risk Reduction
Authors: Suryadi Hendrik 
Published: October 2018

Abstract
Our industry continues drilling more challenging wells - deeper and higher dogleg severity (DLS). Bottom Hole Assemblies (BHAs) have also become more complex and required to sustain higher loads. The current design and engineering practices still rely on prevention mechanical overload which based on calculated maximum stress versus component material yield strength. While fatigue failure is well known and recognized as the primary cause of component twist-offs downhole, but there still limited approach to prevent it during planning phases such as BHA design, execution monitoring, and evaluation. The industry still relies on inspection and traditional cumulative pumping hours tracking as a preventive action against fatigue failure.
Fatigue damage consists of two stages, crack initiation and crack propagation, with crack initiation accounting for most of the total life. Rotating bending is the driving force for fatigue cracking. It induces cyclic stresses and strains at the stress risers, which are the fatigue-critical features. Fatigue data can be presented in the form of S-N curves, where S is the applied bending stress and N is the total life in a number of cycles. An advancement in BHA modeling with the capability of finer detailed finite element modeling of drilling tool component allows for accurate calculation of BHA bending moment distribution. Given a bending moment, the cyclic stresses and strains at the most critical feature of the most critical BHA component can be determined. The life of the most critical component can then be calculated with the stress-life or strain-life curve of the collar material. This governs the life of the entire BHA.
This paper will present the development of new approach on fatigue management workflow which includes bending moment & stress analysis based BHA design, fatigue life prediction and sensitivity analysis during planning and execution monitoring on consumed fatigue life, including job tracking to component maintenance system. The paper will also discuss the accelerated cumulative fatigue due to shock & vibration.
A fatigue management workflow has been created for planning, execution monitoring, and post-job evaluation phases. During planning, the engineer can calculate the expected fatigue life of the BHA and optimize for the expected duration of the job. The result can be used to select reliable components with sufficient fatigue life for the job. While drilling, this method enables the engineer to continuously monitor the consumed fatigue life of any BHA component and make the decision to replace the tool before a failure occurs downhole. After the job, the consumed life can be recorded in the maintenance system to track the remaining life and decide what preventive maintenance is required.
The new modeling approach enables the drilling engineer to optimize performance and managing BHA integrity risk.
Application of Velocity String to Improve Productivity from Bottom pays after Hydraulic Fracturing in Multilayered Low Permeability Reservoir
Authors: Anand Saurabh , Johri Nitin , Chandak Krishana , Vijay Rachit , Tiwari Shobhit , Bohra Avinash , Vijayvargiya Utkarsh , Khemchandani Jivesh , Singh Ishaan , Agarwal Arpit 
Published: October 2018

Abstract
Raageshwari gas field is located in RJ-ON 90/1 Block in western India with Cairn Oil & Gas, a vertical of Vedanta Limited as operator of the field. Multistage hydraulic fracturing is required to achieve commercial production from the highly laminated retrograde gas condensate reservoir. It has been observed in almost all wells that the top high PI zones produce a majority of the gas. The wells have a water column across bottom few fracs which prohibits production from these zones. Water unloading through increased drawdown was not successful because of higher PI of the upper fracs. Coiled tubing-based nitrogen lift of the water column is not commercially feasible. It is important to find a low-cost solution for water unloading since bottom zones account for approximately 30% of total gas in place. A solution has been developed using a customized velocity string design, which can unload the water while maintaining high well production.
Conventional velocity strings are only installed in late life of gas wells when liquid loading is observed. These conventional designs limit the maximum rate to 2-3 MMSCFD and therefore cannot be used in Raageshwari gas field for water unloading as high individual well rates (8 to 12 MMSCFD) is required to meet field plateau production. After reviewing various options, an innovative and unique velocity string system design was developed which incorporates a customized surface spool and string hanging system. This customized design allows combined or independent gas flow conduits as described below:
Through the annulus of velocity string and tubing when higher gas rates are required. Through the velocity string to facilitate liquid unloading due to high gas velocity. Production from both the conduits to meet higher demands than the annulus flow alone.
Well integrity was assured by maintaining two independent barriers during commissioning, production phase and also during future string retrieval.
This paper will discuss in detail the design considerations of the velocity string and surface hanger system to achieve liquid unloading while maintaining high rate gas production. It will also have details on the dual barrier selection process and the design customization that have been done to ensure cyclic liquid unloading and high rate gas production.
This innovative velocity string design is technically a dual completion with a much lower cost and footprint. The same design can be implemented across a wide variety of applications to address well integrity issues, selective zonal production etc. The application of this design in Raageshwari field will ensure planned recovery of gas from the field and will also support plateau production phase. This design can be an efficient and economic technique to develop similar fields.
Design Optimization from 3 Strings to 2 Strings for Deep Wells in Sirikit Field
Authors: Tangkaprasert Phakphum , Rattanachan Sarit , Watchalapong Pimaroon 
Published: October 2018

Abstract
Oil and gas industry continues to increasing demand of more cost-effective well design and operations. Thus, PTTEP Thai onshore drilling team response to the mission by enhancing well design of deep wells in Sirikit Field from three strings to two strings well. This optimization not only reduce cost per well but also unlock reserve in deeper section which used to be uneconomic.
To implement two strings design for deep wells with long open hole section (more than 2,000 mMD), there are key challenges which has to be overcome as per listed below;
Directional control issue Higher torque, drag and side force Difficulty for wireline logging and casing running operation Formation stability and lost circulation Revised Casing Design
To overcome these challenges, not only suite of tools and technologies have to be studied and field proven but drilling practice also has to be reviewed. Risk assessment and feasibility study has been conducted to ensure that this design optimization would results in positive outcome
Since the first implementation in 2015, more than 50 wells have been successfully drilled and completed. The longest open hole section of 2,899.3 mMD with TD of 4,202 mMD has been achieved and average cost saving of more than 25% per well has been realized. Below list the technology applied to overcome challenges;
All targets have been penetrates without directional control issue using Rotary Steerable System (RSS). High drilling torque have been mitigated using high torque drill pipe and torque reduction tools. Reamer and back-reaming out of hole have been used to smoothen wellbore which facilitate wireline logging and casing running operation. Eccentric casing shoe and low-friction centralizers have been used to further aid running casing in high angle wells. High drilling fluid weight has been used in advance to combat formations stability issue. Hence, lost circulation materials (LCMs) have been prepared to mitigate loss circulation due to high ECD. Polymer based spacer system have been used for the wells which have potential of lost circulations while cementing.
BD Gas Field Near-HPHT and Critical Sour Development: A Journey to Maintain Well Integrity
Authors: Tian Yi , Yustendi Kiki , Lian Jihong , Etuhoko Michael , Soufanny Alfon , Jiang Kai , Luo Limin , Xiang Ming , Chang Congbing , Diemert Anthony Paul 
Published: October 2018

Abstract
BD Gas Field is located in offshore in the Madura Strait, Indonesia, and has a total of four producing wells - one vertical (Well Y1) and three horizontal (Well Y2, Well Y3, and Well Y4) from an unmanned platform. Its reservoir was considered near HPHT and critical sour with 8,100 psi bottom hole pressure, 300°F bottom hole temperature, 5.5% CO2 and 5,000 ppm H2S. This paper highlights on the Company journey to maintain well integrity during well design phase, well construction phase, and production phase of BD Gas Field.
During well design phase, material selection and design for 9-5/8 in. intermediate casing, 7 in. production casing, and 4-1/2 in. tubing were based on the expected life of the well and reservoir properties in accordance to the requirements of NACE. Cementing design for 7 in. production casing cement was tested and analyzed in the laboratory for 60 days in the HPHT chamber simulating reservoir properties. Top of cement was designed to the mud line to minimize wellhead growth. Completion design was monobore type and divided into lower, intermediate, and upper completion strings. All packers were V-0 (zero bubble) rating.
Maintaining well integrity during well construction phase was challenging. Batch drilling and completion was applied, and at all times, the wells were required to be suspended with proper and adequate barriers. During drilling and well clean-up phase, inter-casing pressure management (i.e., annulus pressure, wellhead growth monitoring, bleed off program, etc.) was implemented to maintain the casing and tubing integrity.
During production phase, routine wellhead growth measurement, constant monitoring and bleed off program were developed and communicated with related departments. Pressure control valves and alarm system were installed and tested to the annulus.
In additional to the wellhead growth, transverse wellhead movement was observed in one of the wells especially during rough sea conditions. In order to reduce the tranverse wellhead movement which may induce more stress on the surface pipings and connections, it was planned to install under water shims in between the conductor pipe and platform jacket guide funnel.
Some surface piping and platform modification were also considered because wellhead growth leads to limitations on gas production to prevent safety issues.
Evaluation of Relative Permeability Modifiers in Sand-Control Applications: Case History, Results, and Improvements
Authors: Choodesh Attawit , Graham Grant Colin William , Wuthicharn Katha , Ramirez Cristian , Nusyirwan Ahmad , Santoso Doffie Cahyanto 
Published: October 2018

Abstract
Typical sand-control treatments applied in this field are high-rate water packs (HRWPs) or fracture for placement of proppant (FPP). In many cases, the use of a pad is necessary to maximize the amount of proppant placed into the formation and help reduce (bypass) overall skin using onsite data analysis. The gravel pack carrier fluid is a viscosified system with shear-thinning rheological properties and efficiently suspends sand in static conditions. Additionally, this fluid allows substantial flexibility in sand control design for varying degrees of sand support for gravel packing, fluid-loss control, friction-pressure reduction, and a low-damage fluid system (validated with extensive laboratory testing using reservoir cores with carrier fluid to validate returned permeability values).
The objective of the relative permeability modifier (RPM) in sand-control chemical treatments is to prolong hydrocarbon production over time with effective control of water production in one step as a prepad fluid, eliminating the cost and complexity of the water-shutoff treatment stage later as part of well life.
Applying the RPM process has not only reduced water production in these areas, but it has also resulted in more gas cumulative production. It is also important to monitor production for several months after the treatment to determine the success or failure of the application.
Globally, this is the first successful application of RPM delivery in the same aqueous gravel-packing carrier fluid system using a pad fluid consisting of high-grade xanthan polymer as a gelling agent. Implementation of this process provides the operator an additional tool to increase the possibility of hydrocarbon production from a reservoir that has not been considered viable. Use of RPM technique in sand-control completions provides the option to treat wells and control water production resulting from nearby GWC after sand-control treatments.