bluuebunny/crossref_metadata_2025_split huggingface dataset:
Integrated Method to Screen Tight Oil Reservoirs for CO2 Flooding
Authors: Zhang K. , Qin T. , Wu K. , Jing G. , Han J. , Hong A. , Zhang J. , Chen S. , Chen Z. 
Published: October 2015

Abstract
As a result of poor fluid delivery in tight oil reservoirs, oil production drops rapidly at early stages of depletion development. While water flooding only boosts production to a limited extent, CO2 miscible flooding seems a promising technique in improving tight oil recovery. Generally, CO2 flooding is performed only after water flooding gives better results than natural depletion. Since cumulative CO2 injection versus oil production goes up as formation permeability goes down, it is crucial to select suitable reservoir candidates to conduct CO2 flooding to be economically successful. There are several methods of ranking candidate reservoirs for the CO2 enahnced oil recovery (EOR) process based on criteria on reservoir parameters. Nevertheless, few of them take account of an oil recovery increment and risk analysis. In this paper, an integrated method for CO2 flooding reservoir screening criteria is presented, considering asphaltene precipitation and an oil recovery factor increment. This method is based on the least squares method, reservoir simulation, and fuzzy analytical hierarchy process, associated with equation of state (EOS) compositional calculations and compositional modelling. It is applicable in high diversity and can be used as guidance to screen tight oil reservoirs for CO2 flooding.
Estimation of Propped Volume Permeability Using Strain from Geomechanical Modeling of Interacting Hydraulic and Natural Fractures - Application to the Eagle Ford
Authors: Ouenes A. , Bachir A. , Paryani M. , Smaoui R. 
Published: October 2015

Abstract
A new workflow that uses the strain derived from geomechanical modeling of hydraulic fractures interacting with natural fractures is applied to an Eagle Ford well. The derived strain map is used to estimate the asymmetric half lengths that are input in any frac design software able to incorporate this new information. The simplistic symmetric and bi-wing design is revised by adjusting the leakoff coefficient, injection rate, and proppant concentration resulting in asymmetric half lengths that do not exceed the lengths of those provided by the strain map. Once the half lengths and orientation from the frac design match those provided by geomechanical simulation, the propped length and other key results provided by the frac design software may be used to optimize the well's completion. This process could be used iteratively to optimize desired metrics and could also be used to improve reservoir simulation.
The derived strain map may be propagated in the stimulated geomechanical layer to form a strain volume which may in turn be used to estimate the stimulated permeability. In this paper, we used a radial function to relate the stimulated permeability to the strain within the maximum half lengths provided by the strain map. Two calibration constants are needed in the radial functions and could be estimated by history matching or pressure transient analysis. An adaptive Local Grid Refinement (LGR) and variable stimulated permeability provide a realistic representation of the stimulated reservoir volume (SRV). After history matching, the resulting pressure distribution allows an accurate selection of refrac or new well candidates, for optimizing well spacing, and for estimating an accurate EUR.
Optimum Nanosilica Concentration in Synthetic Based Mud (SBM) for High Temperature High Pressure Well
Authors: Wahid Norazwan , Yusof Muhammad Aslam , Hanafi Nor Hazimastura 
Published: October 2015

Abstract
Synthetic based mud (SBM), a non-Newtonian fluid is proven to be the optimum mud for almost all drilling operations, for example in high temperature high pressure (HTHP) well, deepwater, unconventional and long extended reach directional (ERD) well. However, at certain conditions, the good performance of SBM will degrade, particularly due to effect of chemical instability under high temperature. In the light of aforesaid concern, the study on nano particles as a smart-fluid in drilling operations has been gaining attention worldwide. Therefore, this study intends to improve the performance of SBM with silicon dioxide nanopowder (nano-silica) at different concentration. The involving parameters in this study include the manipulation of nano particles concentration per amount of a commercial fluid loss control between 20 to 100 %, and performance at different temperature (275°F and 350°F). The enhanced formulation has given significant benefits by reducing the filtration up to 41.67% and act as the rheology modifier high temperature condition. In summary, the optimum amount of nano-silica has been identified at 40% of total fluid loss control weight to avoid further rheological and filtration degradation.
Hydraulic Fracturing in HPHT Deep Naturally Fractured Reservoir in China
Authors: Li Yongping , Xu Jianhua , Yan Fei , Zeng Siyun , Cheng Xingsheng , Zhang Fuxiang 
Published: October 2015

Abstract
The KQ Foreland Thrust is a typical HP/HT deep gas reservoir in China. The production formation is often buried below 6000m, where the reservoir pore pressure is often over 110MPa and the temperature is over 150 °C. Moreover, the natural fractures richly distribute in the formation. All these factors make the hydraulic fracturing in the KQ challenging, though the fracturing is necessary because the well initial production is often lower than the economic limit production. In previous, even the 20,000psi fracturing equipment was used in the field, the wells can't be totally hydraulic fractured because of the high surface treatment pressure and the limited pumping rate.
The high-density fracturing fluid is the key for HP/HT deep well fracturing, but the fluid weighted with bromide or the VES weighted with CaCl2 are both too expensive to use in the field. So a new fracturing fluid system weighted with nitrate is developed to lower the treatment pressure. The new delayed cross-linked fluid system is high temperature-stability and shearing resistance, and the density can reach 1.35 g/cm3. More important, the cost of new fluid is only 1/5 of the fluid weighted with bromide. Other measures were adopted to ensure the treatment safety and success, such as larger ID pumping tubing, 20,000 psi fracturing equipment and Christmas tree, proppant slug, et al.
Nine layers in six wells were successfully fractured with integrated measures. And the stimulated deepest well is 6988m, and the highest treatment pressure is 136MPa. The well production after fracturing increased by 3 times comparing with the initial production. This makes the well can be economically developed.
These series of technology will provide reference for the similar HP/HT reservoir fracturing to significantly increase the well production.
Special Considerations for Deepwater Well Temperature Prediction
Authors: Chen Zhongming , Xie Liangjun 
Published: October 2015

Abstract
Accurate wellbore temperature prediction is essential in deepwater drilling and completion operations. The wellbore temperature profile is the most dominant factor to consider when the cement slurry properties are designed. These properties are critical to ensure the success of cement placement. Many wellbore temperature simulators described in the literature use a finite difference approach in transient temperature profile modeling. However, for deepwater drilling and completion, the process is more complex. Seawater currents and natural convection cannot be ignored in heat-transfer modeling, especially for subsea pipelines and risers. Also, there are few published results of thermal property correlations for non-Newtonian, high-viscosity cement slurry. Special treatments accounting for transient heat transfer for those cases are necessary.
Mud and cement slurry are typically pumped at lower flow rates for cementing operations. At these rates, apparent viscosity may be used in heat transfer coefficient calculations. However, rheology properties for non-Newtonian fluids are changed abruptly for different models, and so are simulation results. For high viscosity fluids, such as cement slurry, there is a general need for experimentally derived heat transfer correlations.
A novel heat transfer model has been introduced for deepwater cementing. Special considerations for non-Newtonian fluids are included based on theoretical analysis, real field data correlations, and transient heat transfer of deepwater subsea pipelines and risers.
The predictions of the wellbore temperature profiles from this model are validated through measured wellbore temperature profiles, both in offshore and onshore cases. The model has been successfully applied in deepwater circulating, cementing, and hydraulic fracturing. Cases will be presented in this paper.
Production Prediction Based on the Heterogeneity Analysis of the Tight Carbonate Reservoir in the Sichuan Basin, China
Authors: Xie B. , Wang Y. , Zhou X. , Zhao Z. A. , Zhou X. , Zhao X. R. , Li K. X. , Yu D. G. , Xie T. 
Published: October 2015

Abstract
Cambrian and Sinian tight carbonate reservoirs have become a breakthrough in natural gas exploration in China's Sichuan basin. The officially certified geological reserves proved that Moxi-Gaoshiti block is a giant gas field. However, carbonate rocks are diverse and their pore spaces are complex. The storage spaces in carbonate rocks can be divided into matrix pores, fractures, and dissolution pores. The strong heterogeneity in petrophysical properties brings lots of troubles in finding the sweet spot, and it is necessary to incorporate logging methods that provide insight into the pore geometry.
This paper shows a method which incorporates Nuclear magnetic resonance (NMR), borehole images, and induced gamma spectroscopy. NMR is successfully utilized to characterize the pore geometry using a system built upon mercury injection capillary pressure (MICP) measurements and borehole image interpretation. The pores are divided into micropores, mesopores, and macropores. It shows a great advantage in production prediction because the macropores contribute to high initial production rates when they are well connected. The carbonate rocks are then classified into different types based on the pore geometry analysis of NMR and borehole image interpretation, which can be the guide for the further exploration.
Case studies are presented from carbonate reservoirs in the Sichuan basin. A robust and comprehensive petrophysical description of lithology, porosity, pore geometry, permeability, rock types, and fluid saturations is presented. A new understanding of carbonate reservoir heterogeneity is established. The synthetic curve that incorporates several petrophysical properties turns out to be a good prediction of production. Our interpretation methodology was validated well with core data.
This paper discusses a novel combination of open-hole logging tools for the heterogeneity analysis of tight carbonate reservoir in Sichuan basin, and it provides the geologists a handy technique to identify the best pay zone. The workflow can also be applied to other tight carbonate plays in China.
Well Control Simulation Model of Oil-Based Muds for HPHT Wells
Authors: An J. , Lee K. , Choe J. 
Published: October 2015

Abstract
A kick is defined as an unscheduled flow of formation fluids into a wellbore. Kick control is crucial for safe drilling in high pressure high temperature (HPHT) wells. During drilling with oil-based mud (OBM) in these conditions, it is difficult to detect and control a kick because of high gas solubility and mud density change with pressure (P) and temperature (T). The main objective of this paper is to simulate behavior of kicks in HPHT conditions in offshore wells with OBM.
To simulate kick behavior more accurately, it is necessary to consider mud density change with P and T. We select Standing-Katz correlation for base-oil density among three typical methods by comparing them with experimental data available. With the correlation, we update OBM density by use of Hoberock et al.'s compositional model in HPHT conditions. In this paper, by updating OBM density in Choe and Juvkam-Wold's modified two-phase well-control, kick behaviors are analyzed more realistically.
We analyze several cases in 20,000 and 30,000 ft offshore wells with OBM. Under the condition of simulations, mud density decreases as well depth increases because temperature is more dominant than pressure. Pit volume does not always increase as the kick rises to surface because of combined effect of gas solubility, P, and T on kick volume. If we consider the density change of OBM, more surface choke pressure is needed for constant bottomhole pressure with deeper vertical depth and HPHT condition. By applying the proposed method, we can have realistic modeling of wellbore pressure profile and kick behaviors.
Reviving the Mature Field of Bekapai: Integrated Work From Subsurface to Network Optimization
Authors: Muhazir Yan , Supriady Supriady , Kristianto Andy , Herwin Henricus 
Published: October 2015

Abstract
Bekapai is a mature oil and gas field located in the offshore Mahakam Delta, Indonesia. The hydrocarbons are accumulated in complex multilayered reservoirs. Ten platforms were constructed to accommodate the oil production coming from 74 wells drilled between 1974 and 1996. The production started in 1974 with peak production at ~60,000 BOPD in 1978, followed by a period of decline until it reached its lowest point at 1,000 BOPD in 2007.
A field re-development project, so-called Phase 1 initiated in 2008, had increased the production to 10,000 BOPD and 46 MMSCFD by the end of 2013. It consisted of 9 development wells. Following this successful project, a new 3D OBC seismic was acquired and further development plan, Phase 2, initiated, consisting of 10 development wells and gas production facility debottlenecking. Two wells have been drilled in 2014 and contribute in stabilizing the production of 2014 at 11,500 BOPD and 38 MMSCFD, the highest oil production of the past 25 years. The gas production decreases as a consequence to field production facility limitation. It was shelved due to priority of oil development. However, it is expected to increase to 100 MMSCFD in 2015 after the debottlenecking. In parallel, idle wells reactivation to access the shallow gas resources is also reviewed. Besides contributing to gas export, the gas is also used as artificial lift to revitalize the oil wells.
This paper demonstrates the main elements of the redevelopment: evolution of the geological model achieved through seismic and petrophysical data, production management in a complex production system and various optimizations at the production network in order to unlock the production capacity limit through debottlenecking projects and chemical injection at the export line. A continuous effort in even further redeveloping the field is also shown through Phase 2, the objective of which will be chasing the attic oil, blowing down the gas-cap, and double the gas production.
Achieving Zonal Isolation in Critical High-Temperature/High-Pressure Well Through Modeling and Use of Advanced Isolation Materials
Authors: Phyoe Thein , Bermea Jorge Vargas , Jain Bipin , Pallapothu Surya , Hassan Azza El 
Published: October 2015

Abstract
Achieving zonal isolation has always been a challenge when drilling and cementing gas-producing wells in a high-pressure/high-temperature (HP/HT) environment. A generally accepted definition of a HP/HT well is one in which the undisturbed bottomhole temperature at prospective reservoir depth or total depth is greater than 149°C [300°F] and either the maximum anticipated pore pressure of any porous formation to be drilled exceeds a hydrostatic pressure gradient of 97 Pa/m [0.8 psi/ft] or pressure control equipment with a rated working pressure in excess of 68.94 Mpa [10,000 psi] is required.
In the past, HP/HT wells were drilled and cemented in the UAE using conventional cementing design and techniques. Those wells had zonal isolation concerns for cemented production strings, proving that cementing was a critical factor in the HP/HT field. In addition, the wells must bear the stresses generated from injection pressure and temperature changes and frequent cycling of injection during well testing and production. Trapped gas and oil between production and intermediate casing (abnormal annular wellhead pressure) has been globally recognized as one of the serious challenges faced by the Industry from well security and isolation perspective. To tackle the potential safety and environmental hazards of abnormal annulus pressure, better cementing practices and solutions are introduced to improve well life cycle and minimize the frequency of workover operations.
This case describes the use of self-healing cement and flexible and expandable cement to prevent cement failure due to induced stresses and optimize the isolation and ultimately deliver on the objective set for critical exploration well by the Operator.
Developments of ASP/SP Flooding Formulations for Huabei Fault Block Reservoir
Authors: Zhu Youyi , Liu Xiaoxia , Fan Jian 
Published: October 2015

Abstract
Chemical combination flooding technology is one of the effective enhanced oil recovery (EOR) methods for high water cut sandstone reservoirs. Alkali-surfactant-polymer (ASP) flooding has been tested and applied in Daqing oilfield with significant EOR performance. When chemical combination flooding was extended to different reservoirs, one of key techniques is to develop chemical flooding formulations to fit the reservoir conditions. Huabei oilfield is a fault block reservoir with specific geological conditions and reservoir fluid properties other than Daqing oilfield. The average water cut was around 90% by water flooding. Chemical combination flooding is an alternative technique to enhance oil recovery.
ASP and alkali-free surfactant-polymer (SP) combination flooding formulations were investigated for Huabei reservoir conditions based on polymers and surfactants screening tests, surfactant adsorption losses experiments and oil displacement core flooding experiments. The research results lay the foundation of pilot tests for chemical combination flooding applying to the fault block reservoir.
Salt tolerant polymers including comb-shaped polymer KYPAM showed good viscosifying performances than conventional polymers when prepared with Huabei formation water. Petroleum sulfonates (PS) were selected for ASP and SP formulations. Ultralow interfacial tension between crude oil and ASP/SP solution prepared with formation water could be obtained at a widely range of surfactant concentrations from 0.05wt% to 0.3wt%. Adsorption losses of surfactants on core sand showed that the adsorption losses of surfactants were less than 1.00mg/g. Core flooding tests of chemical flooding proved that about 20%-23% incremental oil recovery over water flooding could be obtained by using ASP (1.0wt% Na2CO3 + 0.3wt% PS-1 + 1400mg/L KYPAM) or SP (0.3wt% PS-2 + 1200/1400mg/L KYPAM) flooding with an injection pore volume of chemical slug was 0.5PV.
The experimental results were considered to be technical feasibility and effectiveness of chemical flooding EOR methods for the fault block reservoir, which might present further understanding for chemical EOR field application in Huabei fault block reservoirs.
Case Study of 25 Years of Low Salinity Water Injection
Authors: Zeinijahromi A. , Ahmetgareev V. , Bedrikovetsky P. 
Published: October 2015

Abstract
During the last two decades, low salinity waterflooding as a part of more general varying water composition has become a promising EOR method. Nevertheless, the physics mechanisms of extra oil recovery by low salinity waterflood are not clearly understood. Yet, fines migration and consequent permeability reduction may occur as a result of reduction of water salinity that can divert the water flux. This effect must be accounted in low salinity waterflood modelling. Moreover, the flux diversion due to induced-fines migration could be utilized to improve the reservoir sweep.
In the current study the Tempest software is applied to build a model and history match 25 years of low salinity water injection in Bastrykskoye field (Russia). The model is then used to compare recovery factor for two scenarios of low salinity water (LSW) injection and formation water (FW) injection.
The modeling results show an insignificant change in recovery factor between two scenarios of LSW and FW injection. This low incremental recovery is explained by the production of a significant amount of the reservoir water (FW) before the commencement of low salinity water injection.
A sensitivity study shows that the location of the injectors can highly affect the incremental recovery obtained by LSW injection. A 2-layer model with 5-spot pattern shows a significant incremental recovery (8%) during injection of LSW as compared to the injection of formation water (FW).
Storage of Natural Gas by Adsorption Process
Authors: Arora Anshul , Bachle Anukrati 
Published: October 2015

Abstract
The desire to use natural gas as an automotive fuel at reduced pressures for both safety and compression cost reasons, but without compromising the range of the vehicles, has led to the investigation of the possibility of enhancing onboard storage with the aid of adsorbents.
Natural gas ideally in an adsorbent material will have a density intermediate between that of the liquefied natural gas (LNG) and the compressed natural gas (CNG). Thus, adsorbed natural gas (ANG) will have a very high energy density without the need of low temperature (LNG) or the need of high pressure tanks (CNG). While in principle this is an ideal storage scheme for natural gas as an automotive fuel, one has to find or develop the proper adsorbent material.
ANG technology allows storing big amounts of natural gas at a relatively low pressure (40–60 bars) at room temperature in a relatively thin walled tank filled with adsorbent. This level of pressure allows refueling the tank using simple and cheap equipment or sometimes refueling directly from NG pipelines. At present, activated carbon appears with the greatest potential for storing natural gas at pressures not to exceed 500 psi. In addition, high performance carbons tend to have high densities. Consequently, the high density carbons will occupy a smaller volume in the storage vessel.
This paper reviews the storage technologies for natural gas. Technical comparison is made between storage systems for adsorbent, liquefied and compressed natural gas and cost estimates. We discuss carbon adsorbents, design of storage tanks, cost and safety.