bluuebunny/crossref_metadata_2025 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

Oil Production in Gulf of Thailand Offshore has always been hijacked by high water-cut. Field recovery suffers with most sand RF<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 >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

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

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

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

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

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

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

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

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

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.
Optimised Stimulation Technology Combined Viscoelastic Acid with Jetting Treatments to Enhance Horizontal Well Productivity in AHDEB Oil Field, Iraq
Authors: Zou Honglan , Wang Xugang , Qi Xiaocheng , Kang Jianli , Chen Yandong
Published: May 2016

This paper describe horizontal well CT acidizing design, valid practices and evaluation with good results. The Ahdeb Oil Field consists of sour, heterogeneous carbonate reservoirs with medium porosity (22 - 26%) and low permeability (5 - 20 mD), buried at depth of 2650 to 3150 meters, containing 0.2 - 3.5 mol% H2S and 3.0 - 4.5 mol% CO2, the degree of mineralization of stratum water being as high as 130,000 - 209,000 ppm, producing heavy oil with 22.5—28.9º API.

With very heterogeneous long section (24000ft-32000ft) open to flow, the acid placement and subsequent wormhole penetration depths are challenges. Integrated completion & stimulation techniques have an increasingly wide utilization in Ahdeb Oil Field. Such as: Using of Oil Swell-able Packer for completion of horizontal wells. The strategies related to the acidizing design included various velocity withdrawing pin-point acid jetting and acid. CT is withdrawn continuously from high to low velocity along the whole horizontal section. Viscoelastic acid treatments help to equalize acid distribution by special acid/rock reaction characteristic for each interval. The jetting action helps to remove deep damaged caused by the drilling fluid and completion fluid and improve acid penetration for relative low permeability section. The acidizing simulator predicts the distribution and penetration of acid during the acid treatment. N2 + CT techniques was used to clear up spend acid quickly.

In the past 3 years, there were over 59 horizontal wells that were stimulated with viscoelastic diversion acidizing using CT conducted achieving an averagely doubled production rate which was great contribute to the Ahdeb Oil Field with 120 mbopd of production capability. Besides, a modified evaluation model for horizontal well performance that can be used for field evaluation of acid treatments is developed based on treatment data. Skin factors performance as functions of position and time were calculated and analyzed for stimulated wells.
A Novel Hydroxylpropyl Sulfobetaine Surfactant for High Temperature and High Salinity Reservoirs
Authors: Zhang Fan , Ma Desheng , Wang Qiang , Zhu Youyi , Luo Wenli
Published: May 2016

Reservoirs with high temperature and high salinity are widely distributed in various countries, which contribute an important percentage of oil output in the world. Pilot tests show that chemical flooding technique is one of effective EOR (Enhanced Oil Recovery) ways to improve the oil recovery for mature oilfields. The key technology of chemical flooding is to develop high efficiency surfactants with low cost. In this paper, the betaine surfactant has been synthesized with cheap raw material of fatty acid, and its functional group of hydroxylpropyl sulfo hydrophilic group can improve the heat resistant and salt tolerant abilities of the surfactant. The surfactant was characterized by Infrared Spectra, Raman Spectra and Element Analyzer. The analytical data show that the surfactant is consistent with the designed molecular structure, hydroxylpropyl sulfobetaine. The interfacial tension between the sulfobetaine solution and crude oils achieve ultra-low values (less than 1.0×10-2 mN/m) with temperature range from 30 °C to 90 °C, or salinity range from 20000 mg/L to 120000 mg/L, when the surfactant concentrations are from 0.05 wt% to 0.3 wt%. The parameters of hydroxypropyl sulfobetaine show that it is a suitable candidate for the oil-displacing agent due to its good long-term stability (within 180 days), low critical micelle concentration (4.74×10-5 mol/L), low dynamic adsorptions (0.44–0.72 mg/g), good injectivity and mobility. Oil recoveries increased 20 % - 24 % (OOIP, Original Oil In Place) after water flooding, with both weak alkali ASP and alkali-free SP formulations combined the sulfobetaine. And the oil displacement efficiencies of weak alkali ASP or alkali-free SP flooding have reached to 73 % - 76 %. Excellent properties of the hydroxypropyl sulfobetaine indicate that it is a promising surfactant, which can be applied in reservoirs with high temperature and high salinity.
Yield Stress Measurement and Thixotropic Behaviour of Waxy Crude Oil from the Malay Basin
Authors: Pannu Jaspreet Kaur , Sariman Mior Zaiga
Published: May 2016

Predicting the restart pressure for gelled waxy crude has always been a challenge due to the thixotropic nature of the crude apart from the thermal shrinkage and presence of gas voids within the gelled crude. Thixotropy is a phenomenon where the viscosity decreases under constant shear rate followed by a gradual recovery over time when the shear rate is removed. In pipeline transportation of crude oil, for instance, it is important to characterize the thixotropic behaviour of the crude oil in order for the flow characteristics to be well predicted and understood. Various methods have been proposed to quantify thixotropy, including the well-known "thixotropic-loop" tests. Yield stress is the stress corresponding to the transition from elastic to plastic deformation, the value of shear stress above which the material flows. Existing method defines two yield stresses, one static and one dynamic. While static yield stress is more difficult to measure since most occur at very low stresses and that the measuring methods is still subjected to many debates whereas the dynamic yield stress is relatively easier to be obtained and requires linear extrapolation of viscosity data at high shear rates. Therefore, the measurement for static yield stress was done with oscillatory testing and dynamic yield stress with steady state peak hold testing. All measurement was done under the rheometer with minimized wall slip effect for both statically and dynamically cooled sample. In this paper, the thixotropic behaviour of a waxy crude oil from the Malay basin is explored together with the effects of temperature. Data showed that the extent of thixotropy increases with the reduction in temperature below the Wax Appearance Temperature of the crude oil. For the yield stress measurement, it also exhibited some interesting features of the waxy crude oil. The outcome of the study could then be used to fully understand the nature of the gelled crude.
High Resolution Full Wavefield Inversion: Impact on Imaging and Reservoir Characterisation
Authors: McAdow David , Lazartos Spyros , Routh Partha Routh
Published: May 2016

Seismic imaging has been advancing rapidly over the last two decades, transitioning from post-stack time migration to pre-stack depth migration and from ray-theoretic algorithms (Kirchhoff migration) to one-way wave equation solvers (wave equation migration) and recently to two-way wave equation methods like Reverse Time Migration (RTM). The most recent step in this evolving sequence is Full Wavefield Inversion (FWI), which has rapidly become a focal area of research, development, and application within the geophysical community and industry.

FWI products, unlike migration results, are not depictions of seismic reflectivity, but rather high resolution images of subsurface properties such as compressional and shear velocities and density. The high resolution velocity models generated with FWI can be used to address challenging imaging problems that are difficult to solve using conventional processing tools. High fidelity velocity models will assist in imaging below fault shadows and shallow channels and may also better identify and quantify overpressured drilling hazards. FWI estimates of other elastic paramters, in particular the Vp/Vs ratio, are promising lithology indicators useful in reservoir characterization applications. In addition to imaging challenges, the broadband nature of FWI is ideally suited to address reservoir monitoring problems with the ability to provide high resolution updates of property changes in the subsurface due to production. FWI products, appropriately integrated into an interpretation strategy, will allow us to better understand subtler subsurface features such as stratigraphic traps or non-DHI plays. In our presentation, we will use FWI examples from several real data studies to explain the nature of the process and illustrate some of the potential applications.

Introduction

Full Wavefield Inversion (FWI) is the most advanced and ambitious seismic imaging technology ever conceived. This technology produces the dream of every geoscientist: broadband images of sub-surface rock properties ahead of the drill bit. Seismic imaging has advanced rapidly over the last two decades in lockstep with advances in High Performance Computing (HPC). Traditional seismic imaging methods, such as Beam Migration or Reverse Time Migration (RTM), focus seismic reflections from layer interfaces that the geoscientist can use to map structure and amplitudes that relate to the change in rock properties across layer boundaries. By contrast, FWI simultaneously focuses the image of the subsurface and produces amplitudes that represent actual elastic rock properties within the layers (velocity, density, etc).
XuJiahe Formation Petroleum System in Central Sichuan basin, China
Authors: Liao Xi , Cortis Anthony , Xu Long , Rolph Alan , Ha Kwong Tak , Hua Zhu , Zhang Andy , Zhao Da Hua , Carl Brian S.
Published: May 2016

The Golden Autumn Tight Gas Block is located in the northwest of the Central Sichuan Basin and covers an area of 4,067 km2. Shell, in partnership with PetroChina, has been appraising the gas potential of the area since 2010. The primary target interval, the Late Triassic Xujiahe Formation, is about 1000m thick, and thickens towards the northwest. It is dominated by alternating sand and shale rich members. From bottom to top, the Xujiahe Formation is separated into six, thick members labeled the Xu1 (T3×1) to Xu5-6 (T3×5-6) respectively. The Xu1, Xu3(T3×3) and Xu5-6 members dominantly comprise coaly and calcareous shales versus the sand dominated Xu2 (T3×2) and Xu4 (T3×4) members.

The Xujiahe Formation is considered a self-charged, over-pressured petroleum system with complicated migration history and complex play types. The major source rocks are dark shales and coals within the Xu1, Xu3 and Xu5-6 members. Reservoirs are tight, discontinuous channelized calcarenite sands in shaley formations (e.g. Xu5-6) and regionally amalgamated, largely continuous, litharenite sands in the Xu2 and Xu4 members.

The Jurassic overburden is about 3000m thick and mainly comprised of red lacustrian mudstones and siltstones. Gas and condensate are present and productive from the Xujiahe formation across the entire block. However, zones with higher WGR and even water satured zones occur in the Xu2 and Xu4 members and are interspersed with drier gas zones. In contrast, minimal water production is observed from reservoir sands in the Xu3 and Xu5-6. This indicates various play types within different zones.

Introduction

Exploration and Production History:

The Golden Autumn Block covers an area of 4,067 km2 and is located in the northwest of the Sichuan Basin, in the southwest part of the People's Republic of China. Shell and partner PetroChina have been appraising the gas potential of the block under terms of a PSC (production sharing contract) since May 2010. The block itself has been explored and developed since the 1970s. There are twelve PetroChina/Foreign Cooperation wells and sixteen Shell wells drilled into Xujiahe Formation as of November 2012. Prior to commencement of the PSC, the only extensive production history from the Xujiahe Formation was derived from two older PetroChina wells. One well tested the Xu2 and Xu4 members and has produced economic gas (unstimulated) since 1983. The other one tested the Xu4 and Xu5-6 members with higher gas rates plus some condensate (unstimulated) since 2002. As of end November 2012, four Shell wells demonstrated good initial gas production from the Xu5-6 member, two wells have produced at high rates from the Xu3 member, and one well has produced at high rates from the Xu2 member. With the exception of a single test in the ZZ2 well, all wells show poor Xu4 performance, even after fracture stimulation.
The Historical Statistical Analysis of Spill Incidents in Federal Outer Continental Shelf of U.S
Authors: Tian Hongliang , Lv Jianzhong , Li Wanping
Published: May 2016

Nearly 800 offshore spill accidents in total in the U.S. Gulf of Mexico occurred over the past 50 years. Of these, 80% took place in the oilfield development period, a quarter during drilling and mining operations, and 72% on the platform or rig.

Since 2000, the offshore oil and gas exploration and development has been booming with significantly increased number of oil spills. In 2005, most of leak accidents, including 49 cases with results of leakage of more than 50 barrels and 39 cases of 1~49 barrels, appeared in the history, resulting in total leakage of 16,155 barrels.

There is no obviously direct relations among operating water depth, distance from the shore and accident frequency. Most of accidents involved oil spills, followed by diesel and mud spills. The statistics of spill incidents show oil spills accounted for 48% to 63% and the diesel spills for 15% to 21%. There are less accidents resulting in casualties and the deepwater horizon accidents is the biggest accidents in the history.

Equipment, weather, human factors and external forces (waves, tides and currents, etc.) are the four major factors behind oil spills at sea. Among them, equipment failure is the primary cause for 43% of the total accidents; weather is the second killer, triggering 29%; and human errors involve 18%. In addition, 36% of the total accidents are caused by a single factor, 45% by two concurrent factors, and most of them by the two concurrent factors, bad weather and equipment failure.

Development of offshore oil mining must be corresponding with four conditions: advanced technology and equipment, strong capability of early climate warning, high-quality professional teams, better ability to cope with marine external forces.

Introduction

The U.S. Gulf of Mexico is the earliest developed area among the world's four major offshore oil and gas gathering areas in the past half century and frequent leakage accidents have occurred there due to various reasons. Some laws or clues related to marine spills could be found and key elements in the safety of offshore oilfield development could be deeply understood, through the analysis of the data of these accidents.

There occurred a total of 337 accidents involving more than 50 barrels of leakage in the Gulf of Mexico in the period from 1964 to 2010, with more than seven cases a year; a total of 459 accidents involving 1 to 49 barrels of leakage took place in the period 1970 to 2010, with more than 11 cases a year. These accidents appear during multiple operations period including exploration drilling, production, pipeline laying, transportation, processing, and chemical additives injection. Such accidents are generally results of a variety of factors involving technical equipment, human management and inclement weather.
New HTHP Cutter Technology Coupled with FEA-Based Bit Selection System Improves ROP by 60% in Abrasive Zubair Formation
Authors: Al-Muhailan Mohannad , Hussain Iqbal , Maliekkal Harish , Ghoneim Osama , Nair Prakash , Fayed Mustafa
Published: May 2016

Efficiently drilling the abrasive Zubair sandstone is one of the Middle East's most daunting challenges. Adding to application complexity, the pyritic formation is also interbedded with hard shale streaks and has a compressive strength that ranges between 3–10kpsi. In Kuwait, the formation is first encountered at a depth of approximately 9000ft and been drilled with mixed performance results based on bit diameter. Generally, the large diameter PDC bits are still struggling to achieve the durability objective with some wells requiring more than two PDCs to complete the short 1400ft hole section. In the smaller hole sections, technological advances have overcome the cutter/bit durability issue but with no significant improvement in ROP. The objective of an intensive bit optimization effort has focused on increasing penetration rates while striving to improve overall bit life/cutter durability.

To accomplish the operator driven objectives without time-consuming field trails, the drilling team used a software system to calibrate rock strength. This data was used in conjunction with an advanced FEA-based modeling system to analyze different PDC cutting structures to select a PDC bit with the blade count and shearing configuration that would produce dynamically stable drilling. The bit body would be equipped with a new O2 cutter to increase abrasion resistance and maintain temperature at the cutter tip by using:enhanced HTHP sintering process;refined post-pressing process to improve thermal stabilityoptimized hydraulics to maximizing cutter cooling.

The authors will discuss the bit selection process and modeling system which eliminated costly field trials and the new manufacturing processes that produced the HTHP cutter technology that increased ROP by 60% in the 8-1/2" hole section. The new PDC bit achieved the operator's objective of drilling shoe to TD eliminating several trips for new bits while delivering a significant reduction in drilling costs.

Introduction

This paper is discussing the modern reliable bit selection process and modeling system which can eliminate traditional field trial and error product development system, which is very costly especially when the formation to be drilled is highly abrasive and Pyritic sand formations, where cutting structure durability is very crucial.

Thermal stability of the PDC cutters are of great importance, as quick cutter wear or diamond table loss are caused by high temperatures at the cutter tips while drilling through such highly abrasive fromations. This paper will be looking into the new generation thermaly stable PDC cutter developments that helped to double the PDC cutter durability and further rate of penetration improvements, through a case study of drilling through highly abrasive Zubair formation in Kuwait which quite often Pyritic.
Acquiring and Maintaining Social License to Operate for a Major LNG Project in Papua New Guinea
Authors: Canning James W. , Marru Ian , Walters Kenneth W.
Published: May 2016

Legal license to design, construct, and operate a major project in any country is granted by the government and regulatory bodies of the respective country. Such is the case with the PNG LNG Project currently being built by ExxonMobil and its co-venturers in Papua New Guinea (PNG). The Project, which includes gas wells, a 960 MSCFD gas conditioning facility, a 300 kilometer onshore pipeline, a 400 kilometer offshore pipeline, and a 6.9 Mta LNG plant, would be a major challenge in any country in the world. Government and regulatory approvals were granted in 2009 in order for design and construction to begin, and the project is on track to start up in 2014.

However, a significant hurdle to building the project and operating it for 30+ years is acquiring and maintaining the social license that is "granted" by the indigenous people of PNG who live in the project impacted areas. In a country of almost 7 million people speaking over 800 different languages and living a largely subsistence lifestyle, the Project represents an opportunity to improve their lifestyle and and allow government to fulfill promises and commitments that have been made by governments over many years. The indigenous people use a variety of techniques to negotiate and frequently stop work and hinder progress in order to have their voices heard and their demands addressed. In order for the PNG LNG Project to be a long term success in Papua New Guinea, a comprehensive strategy for acquiring and maintaining social license to operate had to be developed and implemented.

This paper will define what is meant by social license to operate (SLO), discuss the business drivers of SLO and why it is important to manage it with the appropriate people, skills, and strategies, describe ExxonMobil's approach to acquiring and maintaining SLO in PNG, and offer some lessons learned.
Unlocking Reserves, Fracturing Tight Gas-Condensate Bearing Sandstone: The Case History of a North African Field (Algeria)
Authors: Bertoldi Lucio , Perfetto Raffaele , Rinaldi Francesca , Carpineta Gabriele , Granado Luis , Farina Lisa , Secco Giovanni
Published: May 2016

Hydraulic fracturing technique is worldwide used to unlock reserves in tight formations. The Devonian layer, present in this field in the Berkine Basin (Algeria), is gas condensate bearing with a permeability range of 1 to 0.1 md; the zone shows also an highly tectonic stresses, and the frac gradient can rise easily values above 1.0 psi/ft. 3 previous fracturing treatments performed in 2005 and 2006 in 3 vertical wells were without success, due to the high stresses encountered, the wrong frac designs and completion limitation. Aim of this paper is describing the successful multiple propped hydraulic fracturing treatments, placed in a subhorizontal well in March 2012, listing all the actions done in terms of Completion design Materials choice and Frac schedule optimization.

This paper describes also the multiple lessons learned experienced in the execution phase of the multifrac job about frac placement, frac design and completion choice, that have to be considered for the fracturing jobs already planned, in fact the good results of this treatment allowed the Operator to plan a future appraisal/development phase for the Devonian layer.
Development and Application of Pressure Control Drilling System (PCDS) for Drilling Complex Problem
Authors: Liu Wei , Shi Lin , Zhou Yingcao , Wang Ying , Jiang Hongwei
Published: May 2016

In the complex geological condition, drilling operation often encounters the stratum whose fracturing pressure and formation pressure is very near. It is easy to cause drilling complex problems such as well kick and well loss. In order to solve the problems, a pressure control drilling system (PCDS) was developed, including automatic manifold system, back-pump system and auto-control system, which can control the pressure distribution in the entire borehole annular precisely through closed-loop automatic control system. The kernel of PCDS is auto-control system which has three significant characteristic, including an advanced real-time hydraulic method, simple and effective control system, self-adaptive control strategies. The auto-control system configuration composes of field-bus device, controller and workstation which form three levels. Level? is measure and on-site diagnosis level. Level? is monitor and control level. Level ? is optimized control level.

From 2011 to now, the PCDS has successfully finished six field services in China which can provides additional flow-rate and back pressure to compensate for the reduction or increment of bottom hole pressure while making a connection, reduction in rig pump rate, change in mud weight or drill pipe movement and so on. The underbalanced-pressure control technology is also developed which is different from the conventional PCDS technology because the controlled bottom-hole pressure is lower than pore pressure of formation and the gas or fluid can be allowed to come out from formation at a controlled rate which is benefit to protect reservoir and improve ROP.

The applications prove that the PCDS equipment can control the bottom-hole pressure in an exact range and the precise pressure control technology of underbalanced drilling is feasible. So the PCDS equipment can easily adapt to do over-balanced, near-balanced and under-balanced drilling operation and will be more successful in the oil or gas well with safety and fast drilling in the future.
Sea Water Injection Mobile System (SWIMS) for Waterflooding Marginal Offshore Oil Reservoirs in The Gulf of Thailand
Authors: Suthipintawong Tinnaphund , Zyweck Mark
Published: May 2016

Sea Water Injection Mobile System (SWIMS) is a system that is designed to increase recovery efficiency through waterflooding small marginal offshore oil reservoirs in the Gulf of Thailand (GoT). This portable system consists of a submersible pump to lift sea water, chemical injection unit, water holding tank with the ability to treat with oxygen scavenger and biocide and high pressure pump capable of operating at up to 4,500 psi to achieve high rate injection.

The system has a relatively small footprint and is designed to be mobile and flexible to service multiple offshore platforms. The main target reservoirs for SWIMS are small, high permeability, homogeneous reservoirs with a favorable mobility ratio, which allows injection at a higher rate than the production off-take. This ability enables the waterflood to be processed very quickly. When the reservoir is fully repressured and the targeted sweep is achieved, SWIMS can be mobilized to another platform.