bluuebunny/crossref_metadata_2025_split huggingface dataset:
Geomechanical Sweet Spot Identification in Unconventional Resources Development
Authors: Rahman Khalil , Gui Feng 
Published: October 2016

Abstract
Sweet spot identification in unconventional fields generally involves the identification of clusters and intensities of parameters that indicate the resource volume and production-related parameters, i.e., reservoir quality parameters such as total organic content (TOC), porosity, permeability, pay zone thickness, etc. The process usually incorporates interpretation of seismic data, well logs and other data to develop a 3D model that is used to suggest locations for productive wells. While understanding these parameters is essential in unconventional resource development, the potential to achieve productive hydraulic fractures, or the potential to exploit natural fractures, or the potential to achieve both simultaneously determines the feasibility of developing an unconventional resource. There are geomechanical conditions that are favourable to achieve the maximum productivity from stimulation operations. Identifying the geomechanical sweet spots within the field-wide reservoir quality sweet spots is, therefore, essential for optimum placement of wells and hydraulic fractures in unconventional reservoirs. This identification requirement is gaining more and more attention in the industry, which is helping the technique and workflow development. This paper discusses the workflow to identify the existence and properties of geomechanical sweet spots including rock mechanical properties and natural fracture distribution and how they help to decide the vertical location and direction of horizontal wells for optimal reservoir development. The workflow requires a multidisciplinary data set comprising drilling, geology, geophysics, production, geochemistry and geomechanical information. Based on detailed geological understanding, either a 1D or a 3D geomechanical model is built as the foundation for further analysis. Images, seismic data and structural information are the key to develop the understanding of natural fracture distribution. A discrete fracture network (DFN) model, or other definitive models, is required to identify stress-sensitive fracture distributions under different stress conditions. Due to the fact that local in-situ stress and natural fracture properties can be altered by production operations, initial unsweet spots may turn into sweet spots at some stage of production or injection operations. Based on the results of comprehensive geomechanical sweet spot analysis, an optimal development decision can be made based on integrated geomechanics, production and net present value analyses within the identified sweet spots. This paper includes results and illustrations from several case studies completed for a number of fields in the Asia Pacific to demonstrate the concept.
Downhole Real-Time Monitoring for Conventional Waterflooding Wells
Authors: Pei Xiaohan , Sun Fuchao , Jia Deli , Zheng Lichen , Yang Junzheng , Wang Jinzhong , Zhang Jianzhong 
Published: October 2016

Abstract
Waterflooding is the main development mode in China. 80% production comes from waterflooding. Nowadays, there are two conventional waterflooding techniques called eccentric bridge waterflooding and concentric bridge waterflooding. However both these two techniques can not obtain real-time parameters of each layer while injection such as zonal tubing pressure, after-choke pressure, temperature and etc. Lacking of downhole real-time data results in poor reservoir dynamic modeling. In this paper, a downhole real-time monitor was developed. It was placed downhole permanently in each layer. The real-time monitor was composed of battery, rechargeable unit, temperature sensor, two pressure sensors, antenna, and control unit. The downhole tubing pressure, after-choke pressure, temperature and battery power could be monitored continuously and stored on the control unit. Once the data were needed to read, set down communication sub from ground and wireless communication was used to realize data transfer between sub and regulator. The downhole battery could be charged on line to meet the need of different sample time. The downhole real-time monitor has been implemented in a four-layer waterflooding wells in Daqing Oilfield in China. The results show that the monitor could realize downhole tubing pressure, after-choke pressure, temperature and battery power monitoring. On-line battery charging technique was used to ensure its long working time whatever the sample time was. For this well, the sample time was set to 5min according to geological engineer’s advice. All the real-time data were obtained through a short distance wireless way by a communication sub. The results showed its apparent advantage that the downhole real-time monitor had no effect on conventional regulator. All the conventional measurement and adjustment method was the same. The management was also the same as before. Existing conventional waterflooding wells can only obtain real-time data while testing through instruments. Usually there is only totally one hour data per year. The technique in this paper can offer long term real-time data which were used to offer basis for better reservoir understanding and optimization. It is suitable for conventional eccentric bridge and concentric bridge regulator which is most widely used in China, more than 40,000 wells.
The Far-Field Deformation Induced by a Fracture in a Poroelastic Layer with Application to Tiltmeter Monitoring of Hydraulic Fractures in Coal Seams
Authors: Chen Zuorong , Pandurangan Venkataraman , Jeffrey Robert G. 
Published: October 2016

Abstract
Measurements of deformations by using tiltmeters located at large or moderate distances from a hydraulic fracture (HF) have often been used to monitor fracture geometry. The fracture is generally represented as a singular point displacement discontinuity (DD) source, or as a constant DD over a rectangular plane, or as a distributed DD across a fracture plane, and the analytical solution for the induced deformation by a DD in a homogeneous elastic half-space is commonly used directly as a forward model for representing a simple fracture or as a building block for constructing a more complex fracture in mapping the fracture geometry. The mechanical properties of the coal seam in which an HF is placed are typically very different from those of the surrounding rocks. In addition, the poroleastic response associated with fracturing fluid leakoff from the fracture surface into the coal layer may also influence the HF growth and the induced deformation. In order to obtain a correct interpretation of the created fracture geometry and better understanding of the treating pressure behaviour in hydraulic fracturing stimulation of coal to enhance gas production, the mechanical property contrasts and the poroelastic effect induced by fluid leakoff need to be recognised and taken into account.
In this paper, a mechanical model based on the concept of eigenstrain and the equivalent inclusion method is presented and applied to the problem of calculating the far-field deformation and stresses induced by a horizontal fracture located in a formation layer with mechanical properties different from those of the surrounding homogeneous elastic half-space. The fracture is modelled as a constant opening DD across the fracture plane, and the corresponding mathematically equivalent eigenstrain is defined based on the fracture opening and formation layer geometry. A simple one-dimensional hydromechanical model has been presented to approximate the fluid leakoff through the surface of a stationary fracture. The analytical solutions allow for estimating the importance of the poroelastic effect associated with an HF in a coal seam. The variation of the pore fluid content due to fracturing fluid leakoff is characterized by the poroelastic eigenstrain. A relationship connecting the induced far-field deformation and stresses with the fracture and formation layer geometry, the fluid leakoff volume, and the mechanical properties has been established. The proposed method offers a simple and computationally efficient forward model to take into account the effect of mechanical property contrasts and poroelasticity on the deformation induced by the fracture when using tiltmeter monitoring to map the geometry of an HF in a coal seam.
A New Method for Estimating the Production Performance of Water Flooding
Authors: Li Kewen , Liu Changwei , Zhang Qiaoliang , Jiang Ping , Lei Xiao , Gao Hongyi , Jing Fengjiang 
Published: October 2016

Abstract
Pore volumes injected (PVI) has been found to be difficult to represent the longevity and intensity of water flooding in oil reservoirs. In order to find a better parameter to characterize fluid flooding, a new concept referred as to "flushing coefficient" has been proposed, which is a function of time and position. The effects of the viscosity, relative permeability of water phase, pressure gradient, and flooding time are considered in the flushing coefficient. Water flooding experiments were conducted in sandstone rock samples with different permeabilities ranging from about 1.0 to over 1000 md at room temperatures. The experimental data were used to test the new concept.
Old Technique New Insights: Reservoir Properties society of Petroleum Engineers from Pulse Testing
Authors: Filippi Bert , Nabipour Amin , Fukuda Naoki 
Published: October 2016

Abstract
Pulse testing, introduced in the 1960's, is a useful analytical technique to detect communication between wells and estimate interconnected reservoir properties. Despite its potential, it is rarely included in data acquisition programs. This is probably because engineers prefer to use interference testing, which can be easily detected and interpreted by reservoir simulation. Regretfully, the latter cannot analyse pulses which are so subtle that they are hidden within the tidal effects of pressure measurement.
In pulse testing, interconnected permeability is calculated from the time the pulse takes to travel from the producer to the observation well. In this paper, new formulations are presented for both linear and radial flow regimes. These are straightforward, making their application easy. Furthermore, they can detect whether pressure is propagated along channels or more extensive areal systems. The magnitude of the pulse can also provide invaluable reservoir characterisation. For a relatively homogenous system, this amplitude is easily calculated using either radial or linear coordinates. For more complex geometries, such as communication between different sands, detailed studies are required to quantify where and how the connectivity occurs between the producer and the observation well.
Often the pulse is significantly less than 0.1 psi which makes detection difficult, because of tidal effects, and analysis hard to interpret by finite difference simulation. Searching for such subtle changes in pressure takes perseverance. Calculating interconnected permeability by a single equation and determining the geometry of a channel by simple algebra makes the effort rewarding.
Three examples are presented to show how the following equations can be used to determine interconnected reservoir characteristics. Although the data is real, it refers to different fields, the interpretation of which is yet to be finalised. For this reason they are referred to as hypothetical cases A, B and C. These were selected because of the high frequency and the excellent quality of the data. For linear flow k=79⋅x2ϕμc⋅(1tl−1t)/ln⁡ttl For radial flow k=79⋅r2ϕμc2(1tl−1t)/ln⁡ttl
In oil field units: k, x, r,ϕ, μ, c are permeability, distances (x and r), porosity, viscosity and compressibility. The times, t and tl are the hours from the beginning and the end of production pulse (of duration t - t1) to the maximum pressure disturbance at the observation well.
Laboratory and Mathematical Modelling of Fines Production from CSG Interburden Rocks
Authors: Badalyan A. , Beasley T. , Nguyen D. , Keshavarz A. , Schacht U. , Carageorgos T. , You Z. , Bedrikovetsky P. , Hurter S. , Troth I. 
Published: October 2016

Abstract
Twelve clastic core samples from the Walloon Coal Measures, Surat Basin were tested for disintegration in artificially produced fluids varying in ionic strength. XRD data confirm the presence of smectite (water sensitive clay) in the samples. Flow-through rock disintegration experiments demonstrate that the higher the concentration of smectite and soluble plagioclase is, the quicker rock disintegrates in artificial low ionic strength fluid. Pre-soaking of rocks with high ionic strength fluid reduces rock disintegration rate in low ionic strength fluids. This is explained by very strong clay-clay and clay-sand attraction forces, evidenced through zeta-potential measurements, which inhibit rock degradation. For the studied samples it is clear that rock disintegration rate is proportional to fluid velocity. Experimental rock disintegration data are fitted by a power erosion model with two adjusted parameters: fluid ionic strength and Reynolds number. The experimental results satisfactorily agree with theoretical data. Rock disintegration rates are calculated as released particle volume per thickness of interburden layer per day at a fixed Reynolds number and low ionic strength. The laboratory work suggests that keeping wells under strong ionic fluid during shut-in times and a reduction of water production rate will preserve rock integrity for a longer period of time.
Laboratory Study on Surfactant Induced Spontaneous Imbibition for Carbonate Reservoir
Authors: Qi Ziyuan , Han Ming , Fuseni Alhasan , Alsofi Abdulkareem , Zhang Fan , Peng Yuqiang , Cai Hongyan 
Published: October 2016

Abstract
Chemical flooding has been successfully applied in sandstone reservoirs using surfactant-related formulations due to their abilities to reduce interfacial tension (IFT) between injection fluid and oil. This scheme need to be modified to fit the requirement of effective application in carbonate reservoirs that present preferably oil-wet or mixed wet. In this case, the wettability alteration should be triggered by a kind of surfactants that can change the wettability towards water-wet and induce the spontaneous imbibition of injection fluid into the carbonate matrix for higher oil recovery. In this study, 16 surfactant samples were screened aiming at an Arabian carbonate reservoir, among which 3 surfactant samples were selected for spontaneous imbibition experiments using Amott cells at 95°C. The experimental results presented the imbibition was induced by the surfactant solutions compared to effect of the brine. It also showed that brine imbibition recovery decreases with the increase of permeability and initial water saturation. Surfactant can effectively improve imbibition recovery, and cores with higher permeability show better increased imbibition recovery. Imbibition can be divided into three types based on the value of bond number, and recovery as well as recovery rate can also be correlated with bond number. The imbibition model is validated by two imbibition modes – surfactant imbibition and brine imbibition then surfactant imbibition – using UTCHEM simulator. This paper demonstrates the effect of surfactant induced spontaneous imbibition on oil recovery, which should be taken into account in the chemical flooding application for carbonate reservoirs.
Viscosity Modelling of Pyrenees Crude Oil Emulsions
Authors: Tjoeng A. Y. , Loro R. 
Published: October 2016

Abstract
The formation of oil-water emulsions presents a major challenge for the petroleum industry. Emulsions in wells and flowlines cause higher viscosities and lead to larger pressure drops, reducing production performance.
The empirical modelling of emulsion viscosity as a function of water cut is presented. Measurement techniques for emulsion viscosity in a laboratory are explored and their use in a multiphase flow simulator to predict well and flowline pressure drops is explained. The reverse of this methodology can also be used with field data to back calculate the ostensible emulsion viscosity curve.
Using the BHP Billiton operated Pyrenees oil development as a case study, this paper contrasts the laboratory derived and reverse engineered viscosity curves generated across a number of wells that have produced to the point of natural emulsion inversion. A possible mechanism for the differences between the two is proposed.
In the latter part of 2014, a campaign of downhole demulsifier dosing across the Pyrenees fields was intiated with considerable success. The impact of this chemical injection on emulsion viscosity modelling is also explored in detail.
What Conventional E&PD Companies Should Learn from Unconventional Operators
Authors: Ahmad Aladasani , Qutaiba Okasha , Ali Ameen 
Published: October 2016

Abstract
In any economic environment the success of a business is based on the growth of its profits. In that context, today oil and gas E&PD (Exploration and Production Development) companies are challenged with about two thirds decline in revenue and disproportionate operating costs. The situation becomes direr for NOCs (National Oil Companies) where revenue must be compensated to balance the State's budget. Similarly, IOCs and other operators are challenged by taxes, royalties and/or concession agreements with unfavorable return on investment at low oil price regimes. As such there is an inclination to augment hydrocarbon production rates albeit at disproportionate operating costs. Therefore, a need exists to significantly improve business performance.
The objective of this paper is to present an overview of what contributes to an effective business model for oil and gas E&PD companies aimed at reducing operating expenses in addition to augmenting and optimizing revenue. Key strategic programs are discussed such as policy, organization, field development plans, workforce, and contracting philosophy.
The conclusions indicate that typical E&PD planning systems should be fluid in par with the performance of development plans and sensitivity to profitability margins. Observations in this paper capture opportunities to exploit organization capabilities, effectively focus capital investment, and evaluate benefit of acquiring support services versus spinoff in addition to establishing criteria for retaining and selecting specialized services and adopting successful contracting strategies.
The Influence of Gas-Wetting Nanofluid on the Liquid-Blocking Effect of Condensate Reservoir
Authors: Jin Jiafeng , Wang Yanling , Wang Lushan , Zhang Xing , Ren Jinheng 
Published: October 2016

Abstract
Gas condensate reservoirs often experience a sharp reduction in gas deliverability when the wellbore pressure drops under its dew point, this is known as liquid-blocking effect in gas condensate reservoir. Many solutions with limited effectiveness were proposed to figure out the problem, and wettablity alteration is proven to be one of effective measures for liquid-blocking effect. Recent investigations show that the wettability of core near wellbore region can be permanently altered from water-wet or oil-wet to intermediate gas-wetting with the fluorosurfactant treatment, and the mobility and distribution of fluids in porous media can also be significantly improved after gas-wetting alteration. The objective of this study was to find out the effect of gas-wetting alteration by fluorosurfactant modified nano-silica on the gas recovery in methane-liquid-rock system.
The fluorochemicals are widely used to change the surface properties of solid to achieve a surface with a low surface free energy. In this study, gas-wetting alteration on solid surface is achieved with fluorosurfactant and fluoropolymer. In order to obtain a super gas-wetting, nano-silica particles with a size of 40 nm was functionally modified by fluorosurfactant. Contact angle measurement, Owens two-liquid method, and capillary rise in methane-liquid-core system were conducted to evaluate the effect of gas-wetting alternation on the cores wettability and gas recovery.
Data of Contact angle measurement showed that the core wettability can be altered to gas-wetting or super gas-wetting after FG40, FP-2 and FG40 modified nano-silica solution treatment, the contact angles of brine and decane on core surface increased from 23° and 0° to 152° and 127° after treated by 0.5% FG40 modified nano-silica solution, respectively. The surface free energy of cores before and after treatment shows that the sueface free energy decreased from 70 mN/m to approximately 0.61 mN/m. The results of capillary rise and imbibition test verified that of the contact angle measurement and surface free energy, the liquid levels of brine and decane significantly decreased to -20 and 7 mm when the wettability of capillary atered to gas-wetting. Analysis of SEM and TEM indicated that the gas-wetting nano-silica can form a gas-wetting adsorption layer with coarse structures on core surface, which play a vital role in super gas-wetting.
In summary, the cores wettability can be altered from liquid-wetting to super gas-wetting by the novel fluorosurfactant modified nano-silica, and gas deliverability can be significantly improved due to super gas-wetting alteration.
Usability of Geopolymers for Oil Well Cementing Applications: Reaction Mechanisms, Pumpability, and Properties
Authors: Khalifeh Mahmoud , Hodne Helge , Saasen Arild , Integrity Obara , Eduok Ekom I. 
Published: October 2016

Abstract
Portland cement has become the prime material used for zonal isolation; sealing annuli between casings, between casing and formation and finally for plug and abandonment (P&A) operations. However, there are concerns regarding Portland cement such as autogenous shrinkage, high permeability after cracks has occurred, gas influx during waiting on cement (WOC) time, instability at high temperature, ductility and durability. Geopolymers have been suggested as an alternative to Portland cement for oil well applications. Geopolymers are inorganic aluminosilicate cementitious materials condensed as result of a complex reaction known as geopolymerization.
The current work presents the usability of a geopolymeric material specially designed for oil well cementing applications, known as aplite rock-based geopolymer. The chemical reaction of the geopolymeric slurries was determined using calorimetry measurements. The rheological behavior of the geopolymers, such as consistometer consistency and viscosity were examined besides their mechanical properties. The investigation of mechanical properties included uniaxial compressive strength, sonic strength and tensile strength. The pumpability and setting time have been studied by changing mix design of the geopolymeric slurries along with the addition of selected retarders. Finally, microstructure of the cured geopolymers was studied using Scanning Electron Microscopy (SEM).
The results show that slurries have a non-Newtonian behavior like a Bingham material with a small yield stress. The curing pressure reduced the pumpability of the geopolymeric slurries; however, the reason remained unclear. Addition of sucrose by 1.2 wt.% of the total solid content resulted in an optimal accumulative heat release, which showed the highest strength development. Pumpability of the mixes was prolonged by introducing sucrose to the geopolymeric slurries. Tensile strength of the geopolymers was found to be approximately 5 percent of their compressive strengths.