bluuebunny/crossref_metadata_2025_split huggingface dataset:
High Water-Cut Production Remedy by Inflow Control Solution in Challenging Intermittent Channeled Sands Oil Recovery in Gulf of Thailand Offshore
Authors: Platt C. , Houtzager F. , Piyatad T. , Theeranun L. , Mcclure J. , Kienast V. , Pluksataweekul W. , Watcharanantakul R. , GordonGoh K.F. , Wattanaporn P. 
Published: May 2016

Abstract
Oil Production in Gulf of Thailand Offshore has always been hijacked by high water-cut. Field recovery suffers with most sand RF&lt;10% due to premature water breakthrough and by-passed oil. Connecting sand pockets of varying sand quality and huge heterogeneity contrast for commingled inflow has further worsened non balanced production, especially in the progressive development towards horizontal wells' production. However, the deployment of downhole flow control (ICD) in Field-BY as pilot, has revolutionised conventional surface-choke controlled production towards downhole nozzles' inflow and drawdown control. The ICD's pilot, BY-A is selected based on its strategic comparison-value to an existing horizontal well, i.e. BY-B, completed with sand-screen standalone, SAS in the same sand and about the same horizontal length. An 'apples-to-apples' evaluation comparison over the same production time-lapse between ICD-case and the SAS base-case post-job production demonstrated that the ICD's pilot has prevailed in many production factors and completions strategy as such:ICD's well BY-A with ~2 months delay of water breakthrough, unlike BY-B of instantaneous water breakthrough with 40% water-cut in the same period.BY-A has produced &gt;50,000 barrels more oil than that of BY-B for the first 7-monthsICD's application has freed up conventional surface choking-back control upon breakthrough. Instead, more liquid rates are pumped at controlled water-cut that transformed previous production to more rates with more oils.ICD's design and modeling, updated with LWD-derived data near real-time, has optimised the completions cost.
Effectively, lower ICD's screen completions are applied only at sand-contact.
In brief, the entire ICD's design and support together with the post-job production monitoring and optimisation will be discussed. This work provides an insight into transforming an otherwise ordinary horizontal well with typical high water-cut constraints into one of the guiding successful ICD's well that has warranted more ICD's application in the operators other nearby field developments.
A Novel Methodology for Maintaining Mechanical Integrity of High Pressure Relief Systems
Authors: Laskar Sandipan 
Published: May 2016

Abstract
Safe operation and maintenance of emergency systems are of primary importance to the process industries, including upstream oil and gas. The upstream production facilities are usually protected from overpressurization by HIPPS which shuts in the well when local pressure levels exceed a certain threshold. The pressure relief system is often installed as a last safety barrier, when HIPPS fails. One of the critical elements of emergency system is proper design, documentation and to maintain high reliability of this system. In particular, the pressure relief system is an integral part of upstream design and operation; prevention of an accidental release of toxic, flammable or noxious materials from a production facility requires correct design and construction, safe operation, and proper documentation of this system. This paper proposes a basic change in the way relief systems are documented - a requirement in order to comply with OSHA 1910.119 and thereby describes a new methodology and a change in documentation to meet OSHA requirements and other industry standards (such as API 520/521, API-RP 75, 14J). This paper also describes the steps involved in a high pressure relief system evaluation and introduces concept of ever greening to maintain a high reliability of this system. The paper illustrates how an up-to-date relief system leverages management of change (MOC) and helps in setting up the foundation for a strong overall process safety management (PSM) program. The paper will identify the drivers and the benefits of having an evergreening program for pressure relief documentation as well as explore the interdependency of the proposed evergreening elements. The paper will assist upstream facility personnel to utilize good engineering practice in design and documentation of safety relief systems, to meet both onshore and offshore process safety requirements, and to develop consistent company best practices for process safety management. In addition the paper will describe a comprehensive equipment based analysis protocol, preparation of documentation sufficient for design, operational, and audit purposes, and discuss maintenance both of the physical system and design data.
Integrated Approach for Cementing Dual-Casing Running System for Deepwater Wells
Authors: Moroni Nevio , Maliardi Alberto , Salvati Antonella 
Published: May 2016

Abstract
To improve drilling operation efficiency in the riserless tophole section, a new casing running system was introduced in offshore worldwide Eni operation. In this new system, the hole sections for the conductor and surface casing are drilled in one run, followed by running both casing strings in one trip, requiring a single cement job. This system uses a minimum of one trip in the hole compared with conventional techniques used for running casing and cementing in the riserless phase. The cementation of the dual casing has similar objectives to normal surface casing cementation: stable wellhead with cement returns to seabed, no shallow flow in case of shallow drilling hazards, and good cement integrity at the casing shoe to continue drilling operations with minimum wait-on-cement time.
The cementation of the dual casing is challenging for several reasons: the cement job has to cover two concentric annuli, the cement returns are passing through the unconsolidated formation with a high risk of losses because there is no conductor casing set below the seabed, possible shallow flow, large formation washouts close to the seabed depth, and the requirement to develop sufficient compressive strength in a short period of time at very low temperatures to bear the weight of both casing strings and the wellhead assembly.
In offshore deepwater wells, the casing running system has been used several times in water depths from 600 and 2200 m. Initial cement design used conventional lightweight extended lead cement with a neat tail and its drawbacks. The use of this system caused losses close to the seabed and resulted in an unstable wellhead requiring top-up jobs. Careful engineering and planning between the service company and the operator resulted in the development and execution of two successful cement techniques. The first technique consisted of Low Temperature Optimized Particle Size Distribution Cement, followed by neat tail slurry. Because shallow drilling hazards were present, shallow water flow slurries were designed for the job. The second technique consisted of a foamed lead cement followed by a neat tail slurry. Both cement designs fulfilled the job objectives.
The dual-string running technique, combined with an efficient cementing technique, enabled a 40% time reduction in the riserless phase of the well operations while safely achieving the well integrity objectives.
Study on the Theory and Method of Combined Casing Wear Resistance in Deep & Ultra-Deep Well Drilling
Authors: Shengli Chu , Yuqi Pei , Laibin Zhang , Jianchun Fan , Zonghua Cheng 
Published: May 2016

Abstract
The high and steep structure of piedmont areas in Tarim oil field bring serious casing wear problem. Casing wear is one of the important reasons for the frequent accidents and high cost of deep & ultra-deep well. Firstly, the elements and characteristics of the casing drill-pipe tribological system input, friction components and system output are analyzed systematically. Secondly, according to the basic thought of improving tribological system input and changing the friction components to set up 6 wear prevention technological strategies including the body quality control, improvement of the casing wear prevention performance, improvement of the drilling fluid lubrication performance, changing the drill-pipe & casing friction type, improvement of the drilling speed. Thirdly, there are 11 technologies in the wear prevention technology system based on the present situation of technology, such as the vertical drilling technology, a new wear prevention technology, casing material selection, treatment of internal surface, thickening set of pipe wall, solid phase control of drilling fluid, aggravation of material optimum selection, addition of lubricating ingredient, wear prevention joint, drill-pipe protectors and rapid drilling technology. Finally, according to drilling process, 5 integrated casing wear prevention technologies are proposed, including the basic design of wear prevention, the design of expanding wear prevention, the controlling of well quality, usage of wear prevention tools, measures to remedy. These technologies made an integrated perfection of the wear prevention system, offering technical support for the synthetic wear prevention development.

Introduction
The situation of deep & ultra-deep well casing wear is very serious in China. Recent years, in the process of the west oilfield development, more than 10 wells, for example Kecan 1 well, Dongqiu 5 well, Dongqiu 8 Well, etc. have occurred severe casing wear and rupture or collapse accidents, which has brought serious economic loss[1]. Casing wear has become a significant technical problem must be solved in deep & ultra-deep well petroleum engineering. However, the random single wear prevention methods cannot effectively curb the frequent tend of severe accidents induced by casing wear, because casing wear itself is a complicated tribological system. Therefore, it is urgently required needs to establish an integrated casing wear prevention theory and technology system.
Downhole Oil and Water Separation: A New Start
Authors: Sheridan Ed , Ayling Ian , Hixson Jordan 
Published: May 2016

Abstract
Offshore China in the Cao Fei Dian 11-2 field (CFD 11-2), Bohai Bay, Joint Venture Partners Kerr-McGee China Petroleum Ltd (KMCPL) and China National Offshore Oil Corp. (CNOOC) were looking for original solutions to manage their water handling constraints. Downhole oil and water separation was investigated, with the goal of injecting most of the produced water downhole to alleviate surface processing requirements. This paper presents the completion design selected, results and equipment performance (to date), lessons learned and future applications.
Downhole separation is not a new idea. The technology has existed for many years, although most previous installations experienced issues which resulted in limited application of the technology. These issues are reviewed in detail because they were the driving force behind developing a new approach to overcome water handling constraints. To implement the technology at CFD 11-2, a candidate well had to be identified and a new SubSep completion designed. It used two independently controlled ESPs operating simultaneously to provide maximum control and flexibility. Chemical injection was incorporated to enhance separation efficiency using a fast-acting phase separation chemical. Monitoring systems were installed on both ESPs and at the downhole separator to survey all key parameters. A sample line was also included in the completion, and ported to the discharge stream of the hydrocyclone. This enabled real-time monitoring of oil ppm levels in the injected water, and facilitated timely optimization of ESP operating parameters and chemical performance.
The installation reduced the water-to-surface by 8,000 to 9,000 bwpd and achieved an oil carry over of 690 ppm, which was subsequently optimized to less than 300 ppm. The reduced water-volume-to-surface relieved process system pressure and provided an opportunity to increase production from other wells, delivering potential incremental production of up to 500 bopd.
Exploitation and Application of the Ionic Equilibrium Fracturing Fluid
Authors: Lejun Liao , Yan Gao , Dongrui Yuan , Mian Zhang , Zuwen Wang , Wengang Zhao , Jing Li 
Published: May 2016

Abstract
For the shortcomings of the fracturing fluid at president, the paper commenced from several aspects which are the salinity of the fracturing fluid, the ingredients of Inorganic ions, acidic or alkaline, surface or interfacial tension, insolubles and gel breaking residues, then combined them to form the ionic equilibrium fracturing fluid system. The pH and salinity have little influence on the system and there are no insolubles or gel breaking in the fracturing fluid. The pH of the liquid system is 6–6.5 which belongs to the weak acid. The fracturing fluid is the high salinity formation water which is compound with the 4% of KCl and its performance of crosslinking is good. The system has a good performance of heat and shear resistance in the environment of weak acidity and high salinity. The temperature of its heat resistance can be up to 85 ?.

Introduction
At present more than 90% of the fracturing fluid is water-based fracturing fluid and because of the good comprehensive economic, the water-based crosslinking fracturing fluid whose thickener is polymer plant gum occupies the dominant position. The field application of water-based fracturing fluid will go through four main processes: the compound of the fracturing fluid before being put into the well; the support of fracturing construction; contact and react with the formation; flow back after the fracturing. Among them, the first process not only determines the intuitive quality of the fracturing fluid on the ground, but also plays a decisive role in the second stage of fracturing construction; the stand or fall of the second process determines the effect of fracturing transformation.
Experimental Determination of Optimised Production Rate and Its Upscaling Analysis in Strong Water Drive Gas Reservoirs
Authors: Rezaee M. , Rostami B. , Zadeh M. , Mojarrad M. 
Published: May 2016

Abstract
Gas reservoirs were founded as clean and valuable energy sources. Gas recovery from strong water drive gas reservoirs (WDGR) may decrease because water influx may trap gas. The gas is trapped as an immobile phase. WDGR performance is complicated and depends on many parameters and uncertainty associated with reservoirs. In WDGR, accelerating production rate can let more gases scape but question is accelerating with what flow rate.
We investigated the optimum accelerating production rate on WDGR recovery in laboratory scale systems. The experimental flow rates were designed over reasonable range by considering critical rate and Darcy flow condition in first step. By determining optimum flow rate from experiments, the upscaling processes were implemented with a defined theoretical "Sarab" Dimensionless Time Number (TDS) and it was verified by comparing with others porous media length (from 40cm length to 8 cm and 1 meter). The experimental models were contained distinct gas and water zone (aquifer portion) with thickness proportion of one to two. Gas zone was exposed in initial water saturation in all of experiments. These permeable media were systematically characterized in three lengths. Dimensionless numbers were applied to adequately design the experiments. The pressure operational condition was 3160 psia.
We found that optimum flow rate for a WDGR can be obtained in laboratory scale and then can be applied into larger models as well as reservoir sizes with corresponding scale factor of TDS. Connecting of this laboratory flow rate into field application with TDS can be a new revelation into gas recovery and development management of WDGR.
Application of Geophysical Technologies in Lithostratigraphic Reservoir Exploration within Slope Zones of Qikou Sag
Authors: Zhenyong Li , Hongtao Chen , Bingling Li , Yuhai Li , Gangchen Lu 
Published: May 2016

Abstract

Introduction
The Qibei slope is located within the Bohai Bay Basin, southwest of the Qikou sag between the Gangxi fault and the South Dagang fault (Figure1). West of the Qibei slope lies the Kongdian bulge, which is an eastward dipping slope structure with long-term development. Subject to different basement subsidence as well as the differential movements of the two major boundary faults, the Qibei slope can be divided into three flexural slope regions; from west to east, they include the: high slope, middle slope and low slope.
The sandstones of the Es2 and Es3 Member of the Paleogene were supplied by the trough fault and distributed along the eastward dipping slope. The target layer is at the favorable burial depth and the reservoir property is good, correlating well with the slope break structure and the oil sources. It is a favorable zone for lithologic oil/gas accumulation.
The Karatau Mountains Jurassic Succession (Western Kazakhstan): An Outcrop Analogue for the Kalamkas Offshore Reservoir System (North Caspian Sea)
Authors: Davoli Giancarlo , Boz Alberto , Baruffini Luca , Minervini Matteo , Zhemchuzhnikov Vyacheslav G. 
Published: May 2016

Introduction
Outcrop analogues represent a strong help in the building of geological models for exploration and reservoir studies. In particular, whenever the detail of the available subsurface data set is inadequate to describe the complexity of the geological setting, the study of a proper outcrop analogue may help reducing considerably the structural and reservoir architecture uncertainties.
In September 2002, the Kalamkas 1 exploration well successfully tested a multi-layer sandstone reservoir in the north Caspian Sea, the reservoir being composed of a thick succession of interbedded sands and shales, Jurassic in age. Given the encouraging results of the exploration well, and in order to get a better understanding of stratigraphic succession in the offshore license area, Agip KCO (then JV Operator), with the collaboration of the Satpaev Institute of Geological Sciences of Almaty and the Sedimentological Department of Eni E&P Division, decided to carry out a geological field survey in the Karatau Mountain Belt. The Jurassic paralic exposures have been studied with the aim of building the geological model for the time equivalent Kalamkas reservoir. Stratigraphic, sedimentologic and structural data have been collected in order to frame the Karatau and the Kalamkas offshore strata within a common regional geological framework. At the same time, a detailed field work approach, integrated with high resolution satellite imagery and LIDAR data acquisition, allowed to obtain a semi-quantitative reservoir-scale model to be used for driving an early Kalamkas offshore reservoir modelling. This paper illustrates the summary of the field work done in 2004 and 2005 and the application of the results to an early phase of the Kalamkas project workflow.
Experiences, Innovations and Best Practices of Hydraulic Jet Pump (HJP) Application at Remote and Swampy Brown Field in Sembakung Block, Indonesia
Authors: Algrage Ridho R. , Alfaqih Muchammad R. , Priyantoro Tri A. , A. Bhre. , Partomo Alfred Y. 
Published: May 2016

Abstract
Sembakung field was discovered in 1977 and is located in North East Kalimantan, Indonesia. From the reservoir point of view, hydrocarbon is produced from 32 layers of shallow (ranging 1500 - 3500 ft TVD) TBL sandstone formation, which has discontinuous lenses reservoir characteristic with deltaic depositional environment. This environment caused a significant amount of very fine sand production that may be troublesome for most artificial lift types. The reservoir has initial pressure and temperature of 1249 psig and 180 F, with solution gas drive as the drive mechanism. This causes a sharp decline in reservoir pressure; hence the wells cannot flow naturally for a long time. The crude characteristic is ranging from 36–37API deg. and produces with a typical GOR of 150 - 2,400 scf/stb.
Sembakung is located in a remote and swampy area which can only be reached by air and river transportation. As a result, a special rig is required for drilling and workover which will be very costly to mobilize and to operate. Also, the wells must be developed in a cluster system (PAD), making a high inclination in trajectory to reach the target zone.
During 30 years of operations, many types of artificial lift trial have been performed, such as electric submersible pump (ESP), rod pump (HPU) and hydraulic jet pump (HJP). Given that TBL sandstone formation has solid problem, rig mobilization and operations are very costly, high deviated well construction, so HJP became the obvious choice. Currently 43 active oil wells in Sembakung are producing with the aid of HJP as artificial lift, contributing 2,200 BOPD productions.
The aim of this paper is to share the advantages, experiences, innovations and best practices of HJP application in a remote and marginal field, covering rig-less installation of HJP assembly with pump in (PI) and pump out (PO), production optimization by discharge pressure (DP) setting, well surveillance, solid handling options (such as dual vessel application, sand trap and special power fluid for severe sand problem), HJP configuration options, and comparison of surface pump (triplex vs centrifugal pump/HPS).
Application of Facies-Controlled Reservoir Prediction Technology in Slope Zone, North Dagang
Authors: Yuhua Bai , Tinghui Li , Huimin Shi , Mengling Zhou , Hongtao Chen 
Published: May 2016

Abstract
Summary:
The Shahejie (SHJ) Formation is the major productive series in the Gangbei (GB) slope, where both the geophysical and geological conditions are complicated. Affected by the seismic data quality and the ambiguity of the geophysical prediction results, if we apply the conventional geophysical method to carry out reservoir prediction in this area, the accuracy is low and there have been no great breakthroughs for the past few years. Therefore, we put forward the facies-controlled reservoir prediction techniques, which mean using the seismic facies and sedimentary facies to control the seismic reservoir prediction. Starting from the drilling data and based on the sequence analysis results, we carry out a seismic and sedimentary facies study. Combining the sedimentary microfacies of single-well with cluster analysis of multi-attributes seismic facies, and controlled by the sedimentary facies analysis results, we predict the distribution of the favorable reservoir belts. Using above mentioned techniques, we increase the prediction accuracy, the coincidence rate between the prediction results and the drilling data is more than 90%, which yielded a big breakthrough in the litho-stratigraphic exploration in this area.