bluuebunny/crossref_metadata_2025_split huggingface dataset:
Rock Breaking Model Under Dynamic Load with the Application of Torsional and Axial Percussion Hammer
Authors: Xu Zichen , Jin Yan , Hou Bing , Don Jingnan , Pang Huiwen , Lu Yunhu 
Published: November 2016

Abstract
Currently, with proceeding in exploration and development of deep oil&gas, and hot dry rock resources rapidly, it is a high priority to solve the problem of drilling super hard rocks, such as basal conglomerates, tuffs and carbonates in drilling projects. As the drilling efficiency affects the economic feasibility of the drilling project, various methods to reduce the drilling cost have been proposed. Among these alternatives, dynamic load rock breaking method has been further developed in this study to achieve efficient drilling, which can change the way that polycrystalline diamond compact (PDC) operates on rocks.
It is a common problem in drilling in hard strata, such as rate of penetration, stick-slip vibration, chip hold down effect, and high temperature. To solve these problems, torsional and axial percussion hammer has been developed, which can generate both axial and torsional impacts at the same time. The vibration module of this tool, driven by pressurized drilling fluid, can impact on a hammer with a particular slope briefly and the energy instantaneously released in this process can then trigger percussion. The direction of the impact, depending on the resultant force of axial and torsional impact, closer to the dip angle of PDC, indicated that this tool conforms to the rock breaking mechanism of PDC bit. Therefore, this tool is expected to be more effective than traditional axial percussion hammer. In addition to perform structural design and optimize this tool, numerical simulation and laboratory test with designed parameters were conducted in this study. The tool described in this study can reduce stick-slip effect by providing pulse torque and WOB to the bit.
Statistical analysis in this study suggests that the effectiveness of percussion is directly correlated with stick-slip ratio, breakability of rock and frequency of percussion hammer. Based on these findings, rock breaking model with rock's compressive strength, stick-slip ratio and brittleness was established.
This tool was purely made of metal which can endure high temperature and resist corrosion. Field application of this tool in the Ordos and Tarim Basins demonstrates that it has remarkable service life and is effective in speeding up drilling with an average 150% increase of ROP. This torsional and axial percussion hammer is expected to lead to a revolutionary advance in the development of rock-breaking techniques for deep well drilling in hard strata.
Reservoir Characterization of Horizontal Wells in CD Carbonate Formation with Advanced LWD Technology
Authors: Abrar Budi , Ernando Zeindra , Carigali Petronas , Pasaribu Ihsan , Permanasari Dian 
Published: November 2016

Abstract
The CD Carbonate of Ngimbang Formation in East Java basin was deposited in early Oligocene and divided into 5 reservoir targets for development. These reservoir targets were subdivided into different flow units, predominantly due to secondary porosity resulting from karst processes. Identifying these karst zones therefore became important for formation evaluation. Classic high resolution borehole images, combined with sonic, density and neutron logs, and NMR are the most commonly used tools to identify secondary porosity. However, due to the horizontal well design, conventional wireline logging was no longer possible thus Logging While Drilling (LWD) has become the primary data acquisition method. The LWD tool selection criteria have to meet both the geosteering and formation evaluation objectives by considering all drilling challenges. Even though all these measurements are currently available with LWD technology, the complexity of the long horizontal well trajectories and associated drilling risks have been assessed as being too high to run all the LWD services. Therefore, a different technique is required to identify karst zones and to determine saturation along the deeply-invaded karst intervals.
A statistic-based correlation technique using principal component variance between advanced measurements from the multifunction LWD tool such as sigma, neutron capture spectroscopy, and standard measurements such as gamma ray, neutron porosity, density, caliper, and resistivity invasion profile is used to show an indication of karst- or matrix-dominated porosity. The spectroscopy provides accurate lithology volumes and information on grain properties. A simultaneous sigma–resistivity inversion technique is used to determine Archie's parameters in zones where the water salininty is known. The applicability and limitations of the technique are discussed for this particular reservoir environment. The combination of all these techniques along with information from state-of-the-art reservoir mapping technology has provided more complete characterization of the reservoir along the horizontal section.
Three Generations of Wellhead Platform
Authors: Phanichtraiphop Pheerasak , Lertwanichwatana Ratchada , Kiewlek Yoottapong , Sillapacharn Thitinun , Tivanantakorn Weerapong , Sittipod Suchaya 
Published: November 2016

Abstract
PTT Exploration and Production Public Company Limited (PTTEP) is the operator of offshore gas fields in the Gulf of Thailand (GoT), consisting of two major gas fields, namely Bongkot and Arthit. Both assets were initially developed with different partners, therefore, Bongkot and Arthit fields were developed using separate design practices and specifications. Having two different designs of Wellhead Platform (WHP) caused ineffective asset management and operation, therefore, PTTEP decided to generate PTTEP's own specifications and develop a single design of future WHP to be used in both fields, namely Conventional Wellhead Platforms (CWP). However, both Bongkot and Arthit Fields still have undeveloped reserves with varying amounts of recoverable hydrocarbon fluids. As the estimated reserves are not suitable for the capital expense of CWP, these fields are considered as Marginal fields. To secure Thailand's energy supply, PTTEP has designed two alternative WHP designs for sub-commercial prospect reservoirs. The first alternative WHP for marginal fields, called "Medium Facilities Platform (MFP)", is intended to reduce investment cost while maintaining the same operational functions as CWP. MFP could improve economics level in which several prospects become feasible to develop. However, MFP was still not capable to economically develop the remaining small gas reservoirs. Therefore, the second alternative WHP for marginal fields, called "Small Facilities Platform" (SFP) was initiated to further optimize from MFP. With three (3) designs of WHP, one design (CWP) for commercial reserve and two designs (MFP & SFP) for sub-commercial reserve, PTTEP can achieve flexibility in field development by matching suitable platform design with reservoir requirements.
With the current low oil price crisis, oil and gas companies must strive to develop profitable new projects to survive and thrive in the sustainable future. PTTEP has strong determination to continue moving forward and overcome tough challenges. CWP, MFP and SFP are examples of our passion to explore, produce, and secure energy supply.
Proppant Upgrade by Wettability Alteration
Authors: Wang Chuanzhong , Zhang Kewei , O'Neil Bill , Lu Weibing , Quintero Harvey 
Published: November 2016

Abstract
Proppant plays a key role in maintaining fracture conductivity during well production. Silica sand is by far the most commonly used proppant due to its low cost and availability. However, some of frac sands, especially Tier 2 sand, are not always satisfactory under formation conditions. This work presents a cost-effective and environment-friendly method to improve sand quality through changing surface wettability. Meanwhile, the method can dramatically reduce airborne dust during sand transportation and frac operation.
The new approach is based on sand surface modification with a trace amount of a proprietary chemical, which is an eco-friendly liquid and can modify sand surface properties including wettability from hydrophilic to hydrophobic. The treating process is fairly easy and effective by simply spraying the chemical onto frac sand, as the chemical is designed to readily spread on the surface. As a result, the treating process can be easily set up at sand plants or transload facilities.
The treated sand has been examined by various tests. Crush resistance testing shows that the treated sands generate much less fines than the untreated sands; fracture conductivity measurements indicate the treated sands have significantly greater conductivity to flowback water than the untreated sands. Additionally, the method can also be applied for dust control. Field testing shows that most of the airborne dust can be removed from frac sand. Microscopic observation finds that most of the dust particles are adherent to sand grains.
In summary, this method can be a cost-effective and operationally easy way to improve sand quality as well as control silica dust during sand transportation and frac operation.
Completions Optimization Improvements for Unconventional Reservoirs in Saudi Arabia
Authors: Hamid Osman , Rahim Zillur , Faleh Khaled , Omair Ahmed , Ba-Wazir Omar 
Published: November 2016

Abstract
Successful production from unconventional reservoirs is made possible by horizontal drilling and reservoir stimulation through multistage hydraulic fracturing along the laterals. Although hydraulic fracturing techniques have been widely used for unconventional gas stimulation, a considerable percentage of perforations do not contribute to production. The objective of this study is to integrate the geomechanical, petrophysical and completion parameters to precisely design hydraulic fracture for better hydrocarbon production.
Reservoir characterization and optimizing completion parameters are essential for effective well design to improve staging and perforation placement. Challenges in the design of hydraulic fractures include the proper placement of fracturing ports, perforations, and location of isolation packers. The challenges are due to the large variability in fracture gradients, mechanical and reservoir properties, and petrophysical characteristics along the lateral.
Industry experience shows that injection pressures required to fracture the formation (fracture gradient, FG) often vary significantly along a well and that there can be intervals where the formation cannot be fractured successfully by fluid injection due to high in-situ stress.
Geomechanical and petrophysical evaluations providing rock anisotropy and anisotropic stress properties along the wellbore play a fundamental role in completion and hydraulic fracture design. The paper shows how geomechanical and petrophysical properties from open-hole logs and sonic anisotropy evaluations are integrated to compute reservoir quality (RQ) and completion quality (CQ). Intervals with similar properties are grouped to better understand and optimize hydraulic fracture design and operations. This optimization procedure has been applied in a borehole within a potential shale gas reservoir targeting the hot shale facies formation in Saudi Arabia.
Application of this technology resulted in successful completion with optimum fracture stages and perforation clusters positioning thereby improving the initial flow capacity of the well.
How to Design a BHA Rotary Speed Sweet Spot
Authors: Bailey Jeffrey R. , Minkevicius Andrius , Bolzan Alexander , Wilkins Victoria R. , Pokluda Joshua S. 
Published: November 2016

Abstract
Correct placement of the rotary speed "sweet spot" of a bottomhole assembly (BHA) provides multiple benefits towards achieving the ultimate goal of drilling to section total depth in a single trip. Several field case studies will demonstrate the modeling approach and benefits achieved by selecting a preferred rotary speed range and designing the BHA contact points accordingly.
BHA lateral dynamic modeling is now applied pre-drill in nearly every well the operator drills. In most applications, a proposed BHA design is solicited from the directional service provider with the required MWD/LWD tools for the hole section. This baseline configuration is entered into the model. Alternative configurations are then obtained by moving "contact points" through either stabilizer movement, tool rearrangement, or both.
The model results for a suite of such designs are then generated and compared on a single chart, facilitating selection of the BHA that has the lowest vibration indices over the targeted rotary speed range, usually determined by hole size and drill string modeling. In most instances, BHA designs that have been evaluated and run may be successfully reused, provided that the governing assumptions are still correct.
Redesign of the planned BHAs for a well is considered to be an important part of the well planning process, as early redesign provides the most flexibility to modify the tool configurations. Changes made to BHAs late in the process are constrained by tool availability and logistical considerations.
The process of BHA redesign and "tuning" for the desired operating parameters provides greater control over the drilling process, with fewer surprises resulting from poor drilling dynamics. Gaining more control over drilling dynamics has helped to remove one of the most pernicious variables in the well construction process.
In many runs, BHA designs with model-predicted vibrational sweet spots match field observations, and good drilling performance has helped the programs stay on target. Vibration minimization through proper design and operation of the BHA facilitates drilling objectives that include reaching section depth in fewer trips and providing acceptable borehole quality to run casing to depth.
Sand Production Management the Critical Challenge in Zawtika Gas Production
Authors: Junmano T. , Lee B. , Grant G. , Raipairi P. , Viriyasomboon N. , Nopsiri N. 
Published: November 2016

Abstract
To ensure safe operations and to maximize well potential, PTTEPI has formulated a sand production management strategy to reduce risks due to sand production while extracting natural gas resources from the young clastic reservoirs formed during Plio-Pleistocene geological sequence. Over the 2 years of historical production, the strategy has been fine-tuned and enhanced to improve its effectiveness in managing sand production.
The strategy integrates efforts from both subsurface and surface disciplines. It covers initial well completion design to address the need for sand control, continuous recording and analysis of performance data after a well is put on production to monitor and manage sand production within acceptable limits, data acquisition programs to obtain additional information for analysis of sand production, and remedial and mitigation initiatives to address sand production. The following sections will discuss, in more detail, each component of the sand production management strategy.
Evidence for Mesozoic Marine Source in the Western Gulf of Thailand
Authors: Sayers I. L. , Malasri C. , Farrimond P. , White R. 
Published: November 2016

Abstract
This paper documents the findings based on interpretation of the geochemical composition of oils from the Bualuang Field located in the western Gulf of Thailand, and how these oils compare with other oils and potential source rocks in the region. The Bualuang Field is located in Block B8/38, on the eastern flank of one of a series of north-south trending, Tertiary half-grabens which are part of the greater Western Basin.
Eight oil samples from five wells on the Bualuang Field were analysed using gas chromatography (GC), gas chromatography-mass spectroscopy (GC-MS) and carbon isotopic techniques. Selected samples were further analysed by GC-MS-MS. This paper provides a review of these analyses, presenting key geochemical evidence for the likely age and facies of the source of this oil. A comparison is then made between the Bualuang Field oils and other oils from the immediate surrounding area as well as more regionally. In addition, the oils are considered against potential Mesozoic source rocks observed in peninsular Thailand.
The molecular and isotopic analysis of the Bualuang oils show strong similarity, and origin from a carbonate facies (probably marly) as indicated by dominance of C29 hopane over C30 hopane, presence of significant C30 30-norhopane, abundance of C24 tetracyclic terpane and low amounts of diasteranes. Furthermore, the oils are believed to have a marine origin due to the presence of C30 steranes (confirmed by GC-MS-MS), a C26/C25 tricyclic terpane ratio in excess of 1, and the stable carbon isotopic composition. The source of the Bualuang oil is considered older than Tertiary because of the absence of oleanane (typically significant in Tertiary oils), the dominance of 27-norcholestanes (24-norcholestane ratio ca.0.18) and a low C28/C29 sterane ratio (0.58-0.65). Correlation with other oils near Bualuang indicates that this source facies extends further north, with some subtle differences. More regionally clear differences can be observed between the Bualuang oils and other Tertiary oils recognized as either lacustrine or terrestrial in origin. The current study confirmed Jurassic-aged potential source in shales in peninsular Thailand; however, these are quite different to the source for the Bualuang oil. Previous published data for Cretaceous-aged potential source rocks onshore also do not provide a strong correlation.
Importantly this paper provides strong, albeit indirect, geochemical evidence for an additional oil-prone source to consider within the western Gulf of Thailand, which is believed to be Mesozoic in age. One of the key exploration challenges is related to identifying the presence and extent of such a Pre-Tertiary source on seismic data.
A Comprehensive Geomechanical Study for Deep-Water Field Development Planning: A Case Study from Southeast Asia
Authors: Younessi A. , Khaksar A. 
Published: November 2016

Abstract
Several concerns arise at the field development planning stage which may be only answered by geomechanical studies, such as wellbore stability analyses, sanding risk assessments, and studies of compaction and subsidence during the life of the field. These issues can be very important in large projects in deep-water environments. A comprehensive geomechanical study was conducted for an offshore deep-water gas field in Southeast Asia as part of the field development planning.
The study covered a wide range of geomechanical studies from drilling to production stages for the entire life of the field. The geomechanical model was built based on the available logs and data from the exploration and appraisal wells drilled in the field. The model was then used for several geomechanical applications; a) wellbore and fault stability analysis to investigate the effect of the well trajectories on mud weight recommendations and casing design, b) sand production prediction analysis to study the risk of sanding for different completion scenarios, and c) compaction and subsidence analysis to study the impact of depletion on the platform and subsurface designs.
A wellbore stability analysis was conducted to investigate the effect of wellbore trajectory on the safe mud weight window. The analysis suggested that the collapse pressure for any well in the field is dependent on the deviation of wells rather than their azimuths. The impact of the stability of the natural fractures and faults on the upper bound of the safe mud weight window was investigated in detail. The analysis showed that the mud weight required to reactivate the natural fracture and fault intersecting the wells is above the upper bound of the safe mud weight window defined by the wellbore stability analysis.
The sand production prediction analysis showed that sanding is expected from the early stages of production for both open-hole and cased and perforated completions. The analysis suggested that selective and oriented perforations may only delay or reduce the risk of sanding and cannot eliminate it entirely. The compaction analysis showed that the maximum compaction is less than 1% for all reservoirs. This is significantly lower than the general criteria of 3% – 5% which may cause problems for casing and completion systems. Moreover, the maximum total calculated subsidence at the seabed is expected to be below the engineering design limits.
All the methodologies and approaches used to conduct the above mentioned geomechanical analyses, and interpretation of the results are thoroughly explained in this paper. This study highlights the importance of the geomechanical studies for decision making in deep-water field development planning.
Mapping the Bakken with Azimuthal Gamma Ray
Authors: Carrilero Susana Gutierrez , Hinz David , Moake Gordon , Parker Timothy , Carson Dan 
Published: November 2016

Abstract
This paper defines current geosteering practices in the Middle Bakken formation using conventional gamma-ray detectors and discusses the use of a new azimuthally sensitive gamma-ray sensor for more accurate well placement in the target formation.
Two wells were drilled in the Middle Bakken formation using both a conventional gamma-ray detector and a new azimuthally sensitive gamma-ray sensor equipped with an inclinometer to provide continuous inclination. Because omnidirectional gamma-ray measurements can be ambiguous, especially when markers have similar gamma-ray readings, azimuthal gamma-ray wellbore images were used to infer the relative stratigraphic movement of the drilling assembly through the formation.
The two lateral wells presented in this study were drilled entirely inside the target zone between the objective gamma-ray markers. Both real-time and memory data were analyzed using borehole imaging software. Relative and true formation dip angles were calculated after estimating the best depth-of- image. The use of azimuthal gamma-ray images made it possible to determine if the wellbore was moving up or down stratigraphically. A more accurate geological correlation based on the image interpretation, together with an enhanced survey using continuous inclination, made it possible to map the top and base Middle Bakken surface locations. A comparison was established with laterolog resistivity images from the same area that were of higher resolution and higher cost, validating the use of azimuthal gamma-ray for dip calculation.
The azimuthal gamma-ray measurement provides insight into stratigraphic well placement beyond what can be determined from omnidirectional measurements. Data acquired from the gamma-ray image, when combined with enhanced directional-survey measurements, can help to further refine geosteering decisions and reduce uncertainty in wellbore placement.
This paper presents an application of a new, low-cost measurement to allow for better unconventional well placement in difficult-to-interpret situations. As this technique is more widely applied, it may lead to a step change in how lateral wellbores are positioned stratigraphically to increase reservoir exposure.