bluuebunny/crossref_metadata_2025_split huggingface dataset:
Successful Sand Control Campaign for the Development of a Highly Heterogeneous and Multilayered Sandstone Reservoir in Indonesia: A Case Story Offshore Natuna Sea
Authors: Tsangueu Barbara , Wallace Cal , Ginting Job Roy , Sutejo Dian 
Published: October 2016

AbstractThe Natuna Sea in Indonesia contains highly laminated and partly consolidated sandstone, with a combination of highand low-permeability zones, requiring different types of sand control completions (frac packs or high-rate water packs). Previous operators developing the same area have used multizone single-trip completion tools to optimize completion time while tailoring the pumping treatment to each interval’s specific properties. Tailoring the pumping treatment has historically required operators to us rigs with ample deck space or vessels temporarily outfitted with pumping equipment to keep the flexibility of completion types for each zone. In this specific case study, the operator had different constraints but was able to successfully complete the campaign and to overcome the challenges operating from onboard a relatively small jackup rig. The challenges were addressed using an optimized skid-based pumping spread and exclusive carrier fluid technology. In addition, pumping design optimization was done through minifrac analysis to evaluate formation mechanical properties and fluid efficiency to ensure the successful placement of the final treatment. From the completion persepctive, the wells for this campaign were highly deviated, increasing the risk of early screenout due to proppant settling and high tortuosity. Rigorous onsite fluid QA and QC during operations eliminated risks of premature sand settling due to fluid quality, and prefracturing diagnostic tests and use of a low-concentration slurry stage enabled recognition of high near-wellbore friction pressures and then overcoming them when necessary. A total of 24 pumping stages comprised of 16 frac packs and 8 high-rate water packs were successfully placed in eight wells. The treatments used a carrier fluid whose properties were easily adjustable on the fly, enabling appropriate treatments for each zone within the limitations posed by the available equipment and the constraint to optimize completion time. As a main result, production targets have been exceeded by 57% versus initial expectations.
Identifying By-Passed Pay in Complex Water Flooded Reservoirs with Advanced LWD Measurements
Authors: Ge Shengquan , Ma Bin , Liu Fanglin , Li Ting , Liu Yanmei , Yang Xingwang 
Published: October 2016

Abstract
This study addresses the problem of fluid characterization in siliciclastic reservoirs where the resistivity contrast between pay and wet sands is low. Our study field contains connate water of extremely high salinity. The pay sands generally have high irreducible water saturation, which brings down the resistivity reading in oil zones. It is typically difficult to identify hydrocarbon zones with resistivity alone. The low resistivity pay poses a significant technical challenge for the development fields, because the operator must locate the by-passed hydrocarbon and understand the distribution of water floods in order to make future development plans.
The key to accurate fluid characterization in this challenging environment is a good knowledge of formation water salinity. Unfortunately, due to years of water injection to maintain production pressure, water salinity in these reservoirs is highly variable. In such environments, one cannot assume a fixed salinity value when applying saturation equations to well logs.
Thermal neutron cross-section (Sigma) is very sensitive to chlorine in the reservoir rocks and fluids and can be used to distinguish between water and hydrocarbon in a salty water environment. Since both Sigma and resistivity are dictated by water salinity, we can use these two inputs to simultaneously invert for the two unknowns, water saturation (Sw) and water salinity. This process avoids interpretation errors caused by uncertainty in water salinity and does a good job distinguishing bypassed hydrocarbon from water zones. Furthermore, we can use the inverted Sw and salinity to compute continuous hydrocarbon density, hydrogen index (HI) and viscosity downhole.
We applied the above technique to a set of LWD logs acquired in 4 horizontal development wells. We validated our computed water saturation with production history of these wells. The hydrocarbon fluids parameters, ie, salinity, density, HI and viscosity, are cross-checked with surface measurements on produced fluids.
Prediction of Capillary Pressure for Oil Carbonate Reservoirs by Artificial Intelligence Technique
Authors: Busaleh Yasser R. , Abdulraheem Abdulazeez , Okasha Taha 
Published: October 2016

Abstract
Several types of Artificial Intelligence (AI) techniques were utilized to predict capillary pressure in carbonate oil reservoirs with complex morphologies. To develop AI models that predict capillary pressure, a training data set is used that comprises of mercury injection drainage capillary pressure data. In this study, the training data included a set of 70% of 202 core samples that included porosity, permeability and grain density measurements from conventional core analysis tests. Models were developed using this data to predict capillary pressure. Using an error minimization routine, a comparison between the predicted results and laboratory measurements was used to show the validity of this analysis. The model was tested against a new dataset, the remaining 30% of the 202 core samples, that was not included in the training phase. This process was performed on mono-modal, bi-modal, and combined modal data sets.
The analysis of the AI models used in this study, showed that AI has promising potential; however, there is still room for improvement.
Capillary pressure data is one of the most critical parameters used in reservoir characterization and initialization stage of simulation models. Many reservoirs do not have an ample data for a comprehensive evaluation. This method utilizes a small core data set to derive models that can be used to predict capillary pressure in reservoirs that lack these measurements. This proposed approach has three advantages: saves time and money, does not require core samples for new spots in the same area, and uses the available results to their maximum potential from previously destroyed core samples. While previous work did not address the prevalent bimodality of the carbonate rock through the use of Flow Zone Indicator FZI / Rock Quality Index RQI, this paper addresses specifically the AI application to the different rock modals through Thomeer methodology.
Well Planning and Stimulation Optimisation by Integrating 3D Geomechanics for a Horizontal Well in the Northern Cooper Basin
Authors: Gui Feng , Rahman Khalil , Lockhart Duncan 
Published: October 2016

Abstract
Drilling and stimulation of exploration and development wells in the Cooper Basin, Central Australia, has been challenging over the decades due to the high-pressure, high-temperature environment, the high stress anisotropy, and the presence of thick coals. Most of the wells drilled to date have been vertical. To improve production, a study was conducted for a low-permeability tight-sand oil field to assess a horizontal well with multi-stage stimulation. The long horizontal well was expected to pass through a region with varying depletions and lithologies, causing lateral variations in stress and rock properties that could only be captured by a 3D geomechanical model.
A 3D geomechanical model was constructed to provide an integrated and accurate understanding of the field and to facilitate the planning and design of drilling, completion and stimulation of the horizontal well with reduced cost and risks, and to maximize the productivity. Based on detailed 1D geomechanical modelling, a well-centric understanding of the three principal stresses, fluid pressure and rock mechanical properties of the formations was developed for offset wells in the field. The pore pressure distribution and depletion in 3D space was calibrated using well test and long-term pressure survey data. Rock mechanical properties and stresses were populated in 3D space using seismic interval velocities and relationships developed in the 1D modelling, honouring the 3D static geological and structural models.
The model of pressure, stress and rock property variations in 3D space enabled optimization of the casing program and mud weights. Operational best practices to drill the long horizontal well, especially the high-angle build section in overburden coals, were compiled based on a drilling knowledge base developed using data from analogous fields. The use of varying stress and rock mechanical properties along the planned well trajectory in hydraulic fracturing optimization was a differentiating approach to conventional hydraulic fracturing optimization using 1D geomechanics. The treatment was optimized to confine the fracture above the water-bearing formation along the well path. The optimized stimulation design provided the best solution of stages, proppant and fluid selection, and injection schedules to maximize production with minimum cost.
Based on the detailed assessment, it was concluded that the horizontal well is drillable with optimized mud properties and good drilling practices to overcome the instability in coals. In addition, the reservoir section can be drilled safely with lower mud weights whilst still maintaining good wellbore shape. A multistage transverse fracturing program was optimized to improve the production, mitigating the challenges from the extremely low stress contrast between reservoir and the underlying water-bearing zone.
Uncertainty and Risk Management: Waterflood Pilot Design and Surveillance Proposal for a Giant Multi-Layered Sandstone Reservoir
Authors: Wei Chenji , Li Yong , Song Benbiao , Tian Changbing , Li Baozhu , Zhou Jiasheng , Zheng Jie , Luo Hong , Lan Jun 
Published: October 2016

Abstract
Accurately understanding the geological and dynamic characteristics determines the recovery and life cycle of a reservoir. Several uncertainties and risks exist during the development especially for giant multi-layered sandstone reservoirs. Pilot is one of the most effective steps to manage risks and reduce uncertainty, which help better understand the reservoir, expose the conflict during development, propose corresponding surveillance plan, determine development plan, and eventually improve the reservoir performance.
This study focuses on a giant Cretaceous multi-layered sandstone reservoir in the Middle East, which started to produce since 1960s without any energy supply, and the current reservoir pressure is approaching the bubble point pressure. Therefore, water flooding is urgently needed. In order to reduce uncertainty and risks, criteria and workflow of selecting waterflood pilot is proposed by integrating the geology, dynamic data, well status, and existing facilities etc.. 4 pilots are selected and each pilot represents a typical reservoir type to better understand the performance and adaptability of different development plan. Each pilot has its own specific objectives and detailed operation plan. Finally, surveillance plans are proposed based on geological understanding, dynamic behavior, and simulation results.
According to the proposed criteria and workflow, pilots are selected to represent good, medium, and poor reservoir quality respectively. Pilot I is selected as an example to be discussed in detail. The reasons to select this pilot, well pattern and spacing, and perforation strategy discussion are presented. Finally, surveillance is divided into different groups, and implementation plan of different types of surveillance is determined.
This study offers a comprehensive case study that supports the engineers and geologists for better understanding the reservoir and optimizing waterflooding plan for this reservoir. Moreover, it offers an integrated methodology of pilot selection and surveillance proposal for other similar oilfields.
Field Trials of Plugging Oil and Gas Wells with Hydrated Bentonite
Authors: Towler Brian F. , Firouzi Mahshid , Holl Heinz-Gerd , Gandhi Randeep , Thomas Anthony 
Published: October 2016

Abstract
Many field trials have been conducted to explore the effectiveness of using hydrated bentonite as a sealing material for plugging and abandoning (P&A) operations of oil and gas wells. Many of those trials are reviewed here, including trials in Texas, New Mexico, Oklahoma, Wyoming and Queensland, most of which have not been previously reported. All of these trials have been successful, even though a few wells have been eliminated from the programs because they were found to be unsuitable. In most jurisdictions regulation changes are necessary to allow bentonite to be used in order to plug wells. This has been done in California, Texas and Oklahoma. In Wyoming it is currently permitted as the bottom plug in coal-bed methane wells. In Queensland a field trial has been allowed under the experimental materials clause in the regulations.
Reducing Emissions From Oil & Gas Facilities By Use Of Field Proven VOC Tecnology
Authors: Salomone Sara 
Published: October 2016

Abstract
The focus has been to reduce or remove the need for flaring, but very little attention is given to another major cause of greenhouse emission; the venting of pure hydrocarbons from Oil & Gas Facilities especially from FPSO, FSO and trading tankers.
Floating Production Storage and Offloading (FPSO) and Floating Storage and Offloading (FSO) units commonly use inert gas as a blanket gas of the crude oil during offloading of the storage tanks. The inert gas is generated by burning fuel oil or diesel and consists mainly of CO2 and N2 while CO and NOx are side products. During offloading of oil, the displaced volume of liquid is replaced by the generated inert gas to avoid ingress of air (Oxygen) and to keep a slight overpressure inside the storage tanks. When producing or transferring the crude oil, the oil displaces this gas, which is normally vented, resulting in a direct release of hydrocarbon gas to the atmosphere. During these operations, the inert gas is in contact with crude oil. Due to the difference in composition between the gas and the liquid phase, hydrocarbons flash into the inert gas atmosphere. The result is a gas mixture containing up to 80% hydrocarbon gases (methane and heavier components) at the end of a loading cycle. This mixture made of VOC, CO2 and N2 is normally vented directly into the atmosphere. The main component of the VOC is methane, which is a greenhouse gas with Global Warming Potential (GWP) 20 times higher than CO2.
Routine flaring releases CO2, NOx and CO, which are precursors of the ground-level ozone. The ozone at the higher altitude of the Earth's atmosphere (Stratosphere) creates a layer which absorbs the ultraviolet radiations. However, the so-called ground-level ozone (Troposphere area) is toxic and dangerous for health and environment.
Routine flaring and venting form personnel health hazard in addition to cause gas alarm trips with likelihood of subsequent production upsets/shutdowns.
The technology to recovery these emissions has been in use since 1994 on the Norwegian continental shelf. It is also used on shuttle tankers and onshore plants. Recovery of VOC emissions can easily be combined with the recovery of routine Flaring Gas, re-routed into the process and utilized further.
The technology has contributed to substantial reductions of VOC emissions on the Norwegian continental shelf over the last 20 years. Today, an increasing number of oil majors and governments require introduction of both VOC and Flare Gas Recovery, recognizing the major importance of emission reductions both from an environmental and from an economic point of view.
Characterization of Elastic Properties of Lacustrine Shale Reservoir Using Well Logging and Core Analysis
Authors: Yu Hongyan , Wang Zhenliang , Rezaee Reza , Arif Muhammad , Xiao Liang 
Published: October 2016

Abstract
Understanding the elastic properties of rocks is very important for unconventional reservoirs exploration. Unlike marine shale, the lacustrine shale is more complicated with complex mineral composition and frequent sand and shale interbeds. Typical analysis for lacustrine shale gas reservoir rock include: triaxial test, X-ray diffraction (XRD), total organic carbon (TOC) measurements. The mineral composition is different for argillaceous shale and silty laminae shale. The static elastic properties are controlled by clay content, organic matter and porosity. In this work we evaluate elastic properties of above mentioned rocks using experimeal core analysis and well log data. Based on triaxial test, Young's modulus and Poisson's ratio of rocks are obtained by means of the relationship between strain and stress. Argillaceous shale is low to medium strength rock, and silty laminae shale belongs to medium to high strength rock. We find that Young's modulus and Poison's ratio has a negative relationship with clay content, organic matter and porosity which is present by bulk density and neutron porosity logs. The dynamic elastic properties are obtained from cross diploe acoustic well logging data. The dynamic elastic properties have the same controlling factors as static properties. Argillaceous shale and silty laminae shale have significantly different response characteristics in well logging. The porosity is the main factor which leads to the differences between dynamic and static elastic properties. Moreover, it is also found that the ratio of static and dynamic elastic properties is a function of porosity. Hence, density porosity and neutron porosity from the logs are chosen to establish dynamic elastic properties correction model. The correction model is effective in predicting static properties in lacustrine shale gas reservoirs. We conclude that the static properties obtained from the correction model match with core derived static properties.
Produced Gas Utilisation Strategy Study on Low Permeability Reservoir CO2 EOR Process
Authors: Lv Wenfeng , Yang Siyu , Yang Yongzhi , Yang Shenglai , Ma Xiaohong , Li Shi , Wu Chunrong , Hao Mingqiang 
Published: October 2016

Abstract
In the late 1990s, large amounts of low permeability resource plays in the south of Songliao basin have been discovered and made a great contribution to regional development, so far most of them need to be made efforts to improve recovery factors by tertiary method, CO2 flooding has an effective way for this kind of reservoir. CO2 injection pilot was implemented in 2008, it provided invaluable information for extensive areas to make gas injection and production scheme including produced gas recycling.
Most low permeability reservoirs in Song Liao basin have no nature flow, the economic productivity could not be obtained except fracturing. Therefore, it leads to CO2 breakthrough early and produced gas profile variation greatly during the CO2-EOR process. CO2 is from the deeper natural gas field with CO2 concentration over 20%, after separation, the CO2 purity reaches 99% for injection. So how to treat the EOR produced gas is an environmental and economic issue to achieve zero emissions for the whole operations. According to the actual field test data, the vast majority of composition of produced gas are lighter hydrocarbon and CO2. This paper will analyze the composition of gas samples from Jilin oil field, understanding the components of the output gas variation with time. The phase behavior and mass transfer will be characterized by the minimum miscibility pressure (MMP) test and core flood experiment, and the quantitative description method will be obtained through the relationship between the individual component or segment components and sweep efficiency.
Consideration the effect of CO2 impurities on MMP and displacement efficiency, the critical value of CO2 concentration of produced gas is 85%~95%, according to this study, all the produced gas can be reinjection without separation, the value for field application is approximately 90%. That means it would require mixing with pure CO2 for reinjection when CO2 concentration of produced gas is below 90%, otherwise, it could re-inject to oil field directly.
All these results have been applied to achieve reasonable CO2 recycle.
Issues and Challenges with Controlling Large Drawdown in the First Offshore Methane Hydrate Production Test
Authors: Sakurai S. , Nishioka I. , Matsuzawa M. , Matzain B. , Goto A. , Lee J. E. 
Published: October 2016

Abstract
The first offshore methane hydrate production test was conducted in the Eastern Nankai Trough area of Japan in 2013 subjecting gas hydrates reservoir to large drawdowns by reducing bottomhole pressure (BHP) for in-situ dissociation of gas hydrates. This pioneering test has proven the feasibility of depressurization method through demonstration of gas production from a deep water gas hydrates reservoir. Approximately 119,500 Sm3 of gas was produced during a continuous flow period of 6 days. However, reservoir response to a range of drawdown conditions was not possible due to unintended water production through gas line. This paper evaluates the issues with drawdown control that was affected by the water production.
Gas and water released from the dissociation of gas hydrates were separated using a downhole gas separation system. The separated gas and water were produced to surface via two dedicated gas and water lines. Drawdown was planned by pumping out water into the water line using an electrical submersible pump (ESP). Drawdown control was designed to regulate the liquid level (or hydrostatic pressure) in the gas line by controlling the ESP frequency as well as the water line surface backpressure.
Analysis of production data supported by flow simulations indicated that water production through the gas line was the main reason for the loss of drawdown control, i.e., the rising of liquid level was due to water production caused by the produced gas. Water entrainment by gas stream was not the main reason for the water production due to low gas velocity. The produced gas lightened the water column in the gas line, raised the liquid level and lowered the BHP. This process mimics a gas lifting process in a predominantly liquid production well. Since the BHP was largely affected by the liquid holdup as well as the volume of gas in the gas line, it was difficult to regulate the drawdown as intended.
The analysis concluded that water production through the gas line could be prevented if a backpressure regulator was installed at the surface gas line and / or the ESP had high tolerance to the presence of free gas. Lessons learnt from this first field trial has provided valuable information for improving the methods for controlling large drawdown in methane hydrate production system.