bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Large Temperature Difference, Long Column and Narrow Clearance Cementing Best Practices in Halfaya Oilfield
Authors: Nie Zhen , Liu He , Liu Aiping , Sun Fuquan 
Published: October 2012

Abstract
Hundreds of horizontal and deviated cluster wells will be drilled in Halfaya oil field. Placing a nearly 3900 meter long and slim column of cement slurry along 7" production casing/liner in 8 1/2" hole proves to be a great challenge operation done on these wells. The long cement isolation interval translates into large temperature differences between the bottom hole and the top of cement with high circulating pressure during cementing job. In this case, the temperature difference can reach to 60∼70°C and Max. Inclination range is nearly 90 degree. On the other hand, the complicated geological conditions such as: abnormally high pressure (Max. PFP: 2.15g/cm3) with gypsum/salt zones, potential fractured losses and the presence of H2S, CO2 and high salinity aquifer etc. have also brought great difficulties for cementing. So, all these factors results in poor cementing quality in existing wells. This paper focuses on how we developed a new and high performance cement formulation and supporting technologies to effectively solve the cementing difficulties in this oilfield. The new developed cement slurry with density range from 1.30g/cm3 to 1.90g/cm3 has gotten high performance like leak resistance, good rheology ability and especially has good early strength development at the top of cement column. This technology can ensure the cement sets uniformly along the long column and ensure proper zonal isolation. Up to now, 12 wells cementing job have been conducted successfully, 95% of the CBL/VDL well logs show excellent cementing bonding quality. This paper discuss the details of a properly designed cement system and cementing operation and show field implementation result as kind of reference to the future similar cementing cases.
Comparison of DFIT, DST and IFT Permeabilities in CBM Reservoirs
Authors: Taco Gelber , Kamenar Alberto , Edgoose Jeff 
Published: October 2012

Abstract
The Diagnostic Fracture Injection Test (DFIT) is a welltesting technique used to assess the fracture growth, fracture closure and permeability from reservoirs; recently, it has been applied successfully to unconventional reservoirs such as: coal seams, tight sands and shale gas.
The conventional DFIT procedure shares similarities with the author's Step Rate Test (SRT) procedure; the author adapted the SRT for coal seams application in Australia more than 15 years ago, since then it has generated a data base of more than 700 tests. During this period, the SRT was primarily used to assess stress conditions in coal seam reservoirs.
Because of the similarities between the DFIT and STR procedures, we decided to apply the DFIT analysis technique to the SRT data with the aim to assess the coal seam permeability; furthermore, compare these permeability results with Drill Stem Test (DST) and Injection Falloff (IFT) permeabilities of tests undertaken in the same coal seam.
The permeability results from the three methods are not always similar and sometimes differ appreciably; this generates a dilemma for reservoir engineers because they need to choose a representative permeability for their production forecast and reserves recovery assessments. The explanation of these permeability differences relies on the interpretation of coal stress parameters provided by the DFIT analysis.
Furthermore, the appropriate integration of the DFIT, DST and IFT analysis results with wellbore storage, wellbore calliper and leak-off type, will assist the engineers to choose the representative reservoir permeability for their production forecast and reserves estimation; for this reason, running these three tests at the early stages of the exploration project will assists substantially with the property valuations and the planning of future work.
Non-Destructive Strength Index Testing Applications for Sand Failure Evaluation
Authors: Daniels Gillian , McPhee Colin , McCurdy Philip , Sorrentino Yelitza 
Published: October 2012

Abstract
Definitive rock strength data for sand failure evaluation are only available from tests on core plugs, however coverage is limited and core condition and geometry may preclude plugging. This paper presents results from a non-destructive core strength index tester that is less destructive than the Schmidt Hammer and less intrusive, easier, faster and cheaper than the core scratch tester. The portable index hardness tester measures and compares the impact and rebound velocities of a small steel ball after its collision with a rock surface to determine its hardness which in turn reflects the relative strength of the rock. The tester is run at regular intervals along the surface of the core to provide additional data that complement and enhance core rock mechanics data.
Several field examples are presented which illustrate the use of the index tester to optimise core sample selection, evaluate controls on rock strength, and to calibrate and constrain the development of wireline log-based strength models. Importantly, cases are included to highlight exceptions where the tester can produce misleading and even contradictory results.
The integration of index test results with core plug data and log analysis enables development of more robust rock strength models. The methodologies and techniques developed in this work have in turn enabled more accurate sand failure estimates that represent key tools in the development of effective sand management strategies for the reservoir life cycle for a variety of fields throughout the world.
Fracturing Net Pressure Diagnoses Modeling for Volcanic Reservoir
Authors: He Liu , Yang Gao , Lichen Zheng , Honglan Zou 
Published: October 2012

Abstract
Fracture net pressure examination is a widely used method before hydraulic fracturing. It is very crucial for understanding the characteristics of the formation, the complexity of the fracture as well as improving the success ratio of fracture operation, optimizing the fracturing design, evaluating the operating and the fracturing completion. Due to the nature of volcanic reservoir fracture mechanism, filtration mechanism, percolation mechanism, as well as the complex status of fracture initiation and extension of Daqing reservoir, in order to realize the characteristics of reservoir and fractures, and, to ensure the successful field operation, it is very important to conduct the test fracturing and field examination before major fracturing. After practising fracture tests in nearly 100 wells and analyze the effects of different volcanic reservoir physical characteristics on the fracturing operation, we developed six categories of G function pressure analysis methods and four standardized methods for examining the volcanic fracture complexity level by evaluating the characteristic parameters. We also developed fracturing operation technique for volcanic reservoirs and corresponding theoretical explanation methods, and built the specifications to control the operation risk which is based on the fracture test data, realized the accurate control scheme selection and effective execution, as well as improved the controllability on the fracturing operation of volcanic reservoir. According to the data collected from the filed operations, the success ratio is increased from 36% to 90% after applying this method.
HT/HP Fracturing Process String Evaluation and Application in Deep Volcanic Gas Reservoir
Authors: He Liu , Yang Gao , Lichen Zheng , Honglan Zou 
Published: October 2012

Abstract
The function of the fracturing strings is to transfer mechanical energy to crack the formations, and conduct proppant to the formations. Because the deep volcanic reservoir has the properties of deep burial, tight and complex formation lithology, the fracturing operations in such reservoir may encounter the issues of high downhole temperature, high operation pressure and high operation friction. The conventional fracturing strings are not capable of overcoming these problems. The fracturing strings are facing the following challenges:
1. Deeply buried volcanic reservoirs, which are normally deeper than 3000 meters, have very high temperatures, which are higher than 150 degrees Celsius. How to improve the temperature adaptability of the fracturing rubber packer is technically challenging. 2. The formation lithology of volcanic reservoirs is tight and complex, the initiation and extension of the fractures are relatively difficult. The operation pressure is high, so that the fracturing strings and other downhole equipment have to be able to sustain this high pressure. 3. Due to the high discharge rate and large scale operation in the process of volcanic reservoir fracturing, the fracturing strings should have low streamwise friction, strong anti-proppant erosion ability. In order to meet these challenges, we conduct the research on the fracturing equipment and fracturing strings used in the volcanic reservoirs. By studying the theoretical mechanics, optimizing packer structure, improving the temperature and pressure bearing ability of rubber packers, we design special tools such as anchoring tools to improve the adaptability of the fracturing technique, and also generate the safety specifications and operating regulations for the fracturing tools stripping in and out in the deep gas reservoir wells. All these achievements make the large scale fracturing remodeling of the deep gas volcanic reservoir possible. After the field tests, the success ratio is 97.5%.
Successful Application of Well Inflow Tracers for Water Breakthrough Surveillance in the Pyrenees Development, Offshore Western Australia
Authors: Napalowski Ralf , Loro Richard , Anderson Calan , Andresen Christian , Dyrli Anne Dalager , Nyhavn Fridtjof 
Published: October 2012

Abstract
This paper describes the interventionless approach that was successfully executed during the Pyrenees early production phase to identify the timing and location of water breakthrough. Chemical inflow tracers were installed in key production wells within the lower completion along the horizontal production sections. Results from this work have supported the reservoir simulation history matching process and confirmed the performance of the inflow control devices (ICDs). These data in conjunction with the real time rate information from subsea multiphase meters has allowed proactive reservoir and production management that has contributed to the early identification of additional infill opportunities.
Mineralogy and Petrophysical Evaluation of Roseneath and Murteree Shale Formations, Cooper Basin, Australia Using QEMSCAN and CT-Scanning
Authors: Ahmad Maqsood , Haghighi Manouchehr 
Published: October 2012

Abstract
It is found that in the deepest part of Cooper Basin (Permian section in Nappamerri Trough) in South Australia, two shale formations, Roseneath and Murteree have potential to be shale gas reservoirs. However, a comprehensive petrophysical evaluation has not been carried out so far. The free porosity among minerals, pore throat geometry, surface area and structure of micro pores for adsorption and diffusion of gas in these formations have not been well understood.
Two core samples from two wells (Della 4 and Moomba 46) were selected to evaluate mineralogy, free porosity and other petrophysical characterization. Since routine core analysis is not capable of petrophysical characterization of these very tight rocks, the latest technology of image scanning and processing of QEMSCAN (Quantitative Evaluation of Minerals using Scanning Electron Microscopy) and Computerized Tomography (CT) scanning have been used. QEMSCAN is a novel technology to process images from electron microscope to measure size and distribution of different minerals in a rock sample. QEMSCAN when combined with CT scanning can significantly enhance shale rock characterization and reservoir quality assessment. In this study, the main goal is the evaluation of total free porosity, micro pores and natural network of micro-fracture systems in our ultra fine samples.
Based on QEMSCAN analysis, it is found that the sample of Murteree shale has the mineralogy of quartz 42.78%, siderite 6.75%, illite 28.96%, koalinite 14.09%, Total Organic Content (TOC) 1.91 wt%, and pyrite 0.04%, while rutile and other silicates minerals were identified as accessory minerals. Total free porosity is found to be 2 percent. The free porosity is largely associated with clay minerals which shows intergranular linear, isolated and elongated wedge shaped pores. SEM images from the same core sample also show that the pores are mainly present in clay rich zone. QEMSCAN maps have revealed the location of lamination, high and low porosity zones as well as high and low sorption areas. In CT scanning, the porosity found in QEMSCAN, was not identified; however, a network of micro-fracture system in Murteree shale sample is identified.
The influence of pore space geometry on the entrapment of carbon dioxide by capillary forces
Authors: Pentland C. H. , Iglauer S. , Gharbi O. , Okada K. , Suekane T. 
Published: October 2012

Abstract
We investigate the characteristic properties of porous media that influence the entrapment of carbon dioxide (CO2) by capillary forces. It is known that different geological formations can trap different quantities of CO2 but the relationship between formation properties and trapping is poorly understood at present. Advances in micro computed tomography (µCT) techniques now allow the porous media and trapped CO2 clusters therein to be visualised and characterised on the micro meter scale. The context of this work is the geological storage of CO2 where the entrapment of injected CO2 by capillary forces on the pore scale is proposed as a fast and safe method to store injected CO2.
We analyse a series of saturated and unsaturated porous media using µCT; four glass bead packs, a sand pack and a sandstone. In the saturated images the pore space contains brine and residual CO2 (Sr) at subsurface storage conditions. We quantify Sr and cluster size distributions and determine characteristic properties of the porous media through image analysis and the extraction of representative networks. We show that media with narrower pore throats, such as sandstones, trap more CO2 than media with wider pore throats. Numerical simulations performed on the extracted networks do not accurately predict the measured residual CO2 saturations. We discuss the important implications of these results for CO2 storage site selection, containment security assessments, and storage capacity appraisal.
Operational Experience with Subsea Multiphase Flow Meters in the Pyrenees Development, Offshore Western Australia
Authors: Jackson Mark , Napalowski Ralf , Paris Nicholas , Moksnes Paul Ove 
Published: October 2012

Abstract
The Pyrenees Development comprises three oil and gas fields: Ravensworth, Crosby and Stickle. The fields are located in production licenses WA-42-L and WA-43-L, offshore Western Australia, in the Exmouth Sub-basin and are operated by BHP Billiton (Fig. 1). Eighteen subsea wells, including 14 horizontal producers, 3 vertical water disposal wells and 1 gas injection well have been constructed to date and additional wells are planned for infill and to develop additional resources. First oil was achieved during February 2010 and production exceeded 50 million barrels in November 2011. Figure 1Pyrenees Development Location Map
The Pyrenees fields are low relief, with oil columns of approximately 40 metres within excellent quality reservoirs of the Barrow Group. The 19° API crude has moderate viscosity, low gas / oil ratio (GOR), and a strong emulsion forming tendency which makes oil/water separation and accurate well test metering difficult. Early in the project design phase it was identified that the complex subsea gathering system and the need to reduce measurement uncertainties would dictate special attention to production measurement.
Subsea multiphase flow meters (MPFMs) were specified to meet the challenges of production optimization and allocation while at the same time minimizing production deferral for separator testing. Each oil producer is monitored by a dedicated MPFM. With 14 meters, Pyrenees is among the largest subsea MPFM installations worldwide.
This paper describes the process of MPFM qualification and commissioning together with their performance over 2 years in the field. We show how close cooperation between the Operator and MPFM Vendor has enabled quality rate measurements of emulsified production despite large changes in producing gas/oil ratio and water cut.
While the primary justification for Pyrenees subsea MPFMs was production allocation and optimization, interpretation of transient water cut and GOR data proved valuable for production and reservoir engineering applications. Examples of proactive reservoir and production management including optimizing drawdown of Inflow Control Device (ICD) equipped wells, optimizing well lineup and gas lift to commingled wells are presented.
Drillpipe for Shale Plays - Requirements, Considerations and Lessons Learned
Authors: Jellison Michael , Brock Jim , Muradov Andrei , Morgan Dan , Rowell Jim 
Published: October 2012

Abstract
Shale drilling for both natural gas and hydrocarbon liquids has increased dramatically in North America over the last several years. Shale oil and gas deposits are known to exist all over the globe including Australia and the rest of the Asia Pacific. This paper discusses the requirements for drillpipe in shale drilling applications along with a review of some of the challenges and problems associated with the drillstring in these critical applications. Most wells are horizontal with long departures. Typical wells in the Balkan Shale are 17,000 ft MD, 11,000 ft TVD with a 6,000 ft horizontal reach. Drilling these wells puts huge demands on the drillpipe and rotary shoulder connections and pushes the drilling equipment and rig crews beyond the requirements of typical onshore well construction projects. Many, if not most, of the shale wells require advanced design, double shoulder connections (DSC) on the drillstring to provide the enhanced torsional strength and streamlined connection dimensions required to effectively drill these prospects. The paper presents connection design solutions along with considerations for safe and efficient running procedures. Although, the advanced DSCs are designed to be transparent to normal drilling operations, compared to standard API connections, some problems have been encountered. The paper addresses these running and handling issues and provides guidelines to mitigate these problems. Excessive tool joint and drillpipe body wear have also been encountered in several shale plays. This is discussed, along with recommendations to limit wear. Stick-slip has created drillstring problems on several wells. Stick-slip can cause damage to the drillpipe and, in the extreme, downhole connection back-offs have occurred. The paper looks at aspects of case histories to illustrate these issues and provides lessons learned to improve shale drilling operations in North America, the Asia Pacific and other regions of the world.
Floating Production Platform Selection for Developing Deepwater Gas Fields off North West Australia
Authors: Xia Jinzhu , D'Souza Richard 
Published: October 2012

Abstract
Producing and delivering North West Australia (NWA) deepwater gas reserves to LNG plants poses unique challenges. These include extreme metocean conditions, unique geotechnical conditions, long distances to infrastructure and high reliability/availability requirement of supply for LNG plants. A wet or dry tree local floating host platform will be required in most cases. Whereas semisubmersible, TLP, Spar and floating LNG (FLNG) platform designs all have the attributes to be a host facility, none has been installed in this region to date.
This paper will address important technical, commercial and regulatory factors that drive the selection of a suitable floating host platform to develop these deepwater gas fields off NWA. Linkages between key reservoir and fluid characteristics and surface facility requirements will be established. A focus will be on the unique influence of regional drivers and site characteristics including metocean and geotechnical conditions, water depths and remoteness of these fields.
Estimating Zonal Gas-in-Place in a Commingled Well Using Results from Production Logs
Authors: Last Nick 
Published: October 2012

Abstract
It is becoming increasingly common to commingle two or more separate gas reservoirs in a single wellbore, especially in stacked-sand environments such as those frequently found in the Asia-Pacific region. Providing certain conditions are met, the total gas initially in place (GIIP) of the commingled reservoirs can be estimated using conventional material balance techniques. However, allocation of total GIIP to individual reservoirs presents a significant challenge. This paper describes how production logging (PL) results can be used, in conjunction with suitable dynamic modeling techniques, to define GIIP on a zone-by-zone basis.
The Selective Inflow Performance (SIP) technique for estimating pressures and deliverability of individual zones using suitable PL data is well established. Combining SIP results with other well information (including initial reservoir pressures and total well production) allows allocation of production to individual zones and calculation of their associated GIIP. This is done using a commingled well model (CWM) that matches both the initial well conditions and those obtained from the SIP results at the time of the PL. The paper sets out the minimum features of such a CWM.
The ability to allocate production to an individual zone, and to estimate its associated GIIP, presents opportunities to make better reservoir management decisions than is possible when only total-well information is available. Such decisions, including the location and timing of infill or step-out drilling, or whether to target well intervention at particular zones, may have large financial repercussions.
Successful Application Of 4D Seismic In The Stybarrow Field, Western Australia
Authors: Hurren Chris , Broad Carrie , Duncan Guy , Hill Robin , Lumley David 
Published: October 2012

Abstract
The Stybarrow Field is a moderately sized biodegraded 22° API oil accumulation reservoired in Early Cretaceous sandstones of the Macedon Formation in the Exmouth Sub-Basin, offshore Western Australia. The reservoir is comprised of excellent quality, poorly consolidated turbidite sandstones up to 20m thick. The field lies in approximately 800m of water and has been developed with five near-horizontal producers and three water injection wells. The Stybarrow development came online at an initial rate of 80,000BOPD in November 2007.
Due to the lack of significant aquifer support, water injection was planned from start-up for pressure maintenance. Acquisition of a variety of data types have enabled key subsurface challenges to be addressed both before and during production. Structural and stratigraphic complexities influence connectivity and therefore must be fully evaluated in order to achieve optimal sweep. A feasibility study concluded that Stybarrow would be a good candidate for 4D seismic monitoring. Two monitor surveys were acquired and, along with other reservoir surveillance techniques, have been used to refine the geological model.
The first monitor survey at Stybarrow was recorded in November 2008. The results of this survey were in agreement with prior 4D modelling and supported the drilling of a successful development well in the north of the field. A second monitor survey was recorded in May 2011, three and a half years after first oil and at 70% of expected ultimate recovery. This survey is currently being analysed to determine if sweep patterns have changed.
The 4D surveys have proven to be an important tool for understanding subsurface architecture and dynamic fluid-flow behaviour. The results of both 4D seismic surveys have provided significant contributions to understanding the dynamic behaviour within the reservoir to facilitate optimal reservoir management.