bluuebunny/crossref_metadata_2025_split huggingface dataset:
Parameters Affecting Load Recovery and Oil Breakthrough Time after Hydraulic Fracturing in Tight Oil Wells
Authors: Zanganeh B. , Soroush M. , Williams-Kovacs J. D. , Clarkson C. R. 
Published: October 2015

Abstract
After hydraulic fracture treatment, wells typically produce significant volumes of water, which is primarily recovered fracturing fluid. The amount of fracturing fluid produced back is called load recovery. Single phase water production may continue for several days before oil breakthrough from the formation occurs. A wide range of load recoveries (15%–80%) are reported in the literature, depending on various reservoir, fracture, pumping and operational parameters. This study conducts a comprehensive numerical and statistical analysis to identify the most important parameters affecting load recovery. The sensitivity of oil breakthrough time to these parameters is also investigated.
A fit-for-purpose model was created using a commercial coupled reservoir flow/geomechanics simulator to simulate fracturing treatment and flowback operations. Water and oil production trends, and flow regimes observed in the model, are verified using rate-transient analysis (RTA). The effect of twenty parameters including pumping rate, shut-in time, producing bottomhole pressure, production rate constraint, matrix porosity and permeability, matrix and hydraulic fracture compressibility, relative permeability end points and capillary pressure on load recovery and oil breakthrough time is investigated by utilizing Design of Experiment (DOE). The developed model considers non-uniform leak-off during pumping, providing a better understating of water retention, while the application of the DOE method allows the effect of various parameters and their interaction to be studied rigorously.
A critical finding is that the majority of total load recovery occurs within the first three months of production. Furthermore, matrix permeability, shut-in time, connate water saturation and fracture compressibility, were found to be the most dominant factors, which can impact the load recovery by up to 22%, 15%, 14%, and 13%, respectively. Matrix permeability, production rate constraint, fracture residual oil saturation and shut-in time are four of the prominent parameters affecting oil breakthrough time.
Understanding the impact of operational parameters such as shut-in time and production rate can help industry to implement recycling/disposal options and ultimately optimize load recovery. This can also create significant environmental compliance benefits for operators in addition to benefitting operational efficiency.
Produced Water: Influence of Organic Acids on the Gelation of Fracturing Fluids
Authors: Weissenberger Markus C. , Lee Adrienne , Wasdal Tim 
Published: October 2015

Abstract
Organic acids, such as acetic or formic acid, are ubiquitous in produced waters from petroleum-producing basins. The chosen measurement system was a reversed-phase mode High Pressure Liquid Chromatography (HPLC). This method can overcome the matrix problem of high inorganic ion concentration in produced waters. This is possible due to the usage of a highly hydrophobic stationary phase, which is not interacting with the high amount of inorganic ions present in produced waters.
In extension to the initial publication the influence of organic acids on the hydration and gelation for zirconium and borate cross-linked fracturing systems was determined in detail. This was done with the original brine samples from different locations and with artificial brines which were doped with different organic acids at different concentrations. It could be shown that in the presence of organic acids the usage of borate cross-linked fracturing gels, which requires a high pH of 9 to 11, is impossible due to a hindered crosslinking. Only with economically meaningless loadings of basic buffers the pH could be increased high enough to achieve a weak crosslinking.
As the natural pH of produced waters in the presence of organic acids is around 4, tests were carried out with zirconium cross-linked systems. These fracturing systems, which require a low pH of 4.5 to 5, were tested in both artificial brines and the actual produced waters with organic acids. It could be shown that in the presence of 600 mg/L or 1200 mg/L organic acids a stable cross-linked gel could be achieved. This is possible even in the presence of high salt concentrations up to 250,000 mg/L.
The conclusion of this work is that in the presence of a higher concentration (from around 500 mg/L) of organic acids like formic or acetic acid the substitution of a common borate cross-linked fracturing system with a zirconium cross-linked fracturing system should be considered.
Inflow Performance Relationship for Unconventional Reservoirs (Transient IPR)
Authors: Shahamat Mohammad Sadeq , Tabatabaie S. Hamed , Mattar Louis , Motamed Ehsan 
Published: October 2015

Abstract
Inflow Performance Relationship (IPR) describes a well's inflow rate at various flowing pressures. The conventional IPR assumes stabilized (i.e. boundary dominated) flow conditions. Unconventional reservoirs may take several years to reach stabilization and their performance evaluation involves complex modeling of stimulated reservoir volume (SRV) and requires advanced reservoir engineering knowledge. As a result, some of the traditional IPR concepts and notions are not applicable.
This paper discusses the behaviour of "transient" IPR in comparison to "stabilized" IPR, the meaning of slope and intercept in transient IPR, and the differences between IPR of conventional and unconventional reservoirs. In addition, the effect of production history on transient IPR of a well is examined.
The result of this study is a methodology for generating a "practical" transient IPR for multi-frac'ed horizontal wells. After history-matching the well's performance, the resulting reservoir model is used in a straightforward procedure to obtain the transient IPR in a form similar to the conventional IPR. This means that it can be used with nodal analysis for determining the effect of changing flowing pressure on the inflow rate.
The methodology presented in this paper maintains the simplicity of use of IPRs, yet accounts for unconventional reservoir complications. The "practical" transient IPR can be used directly by the production engineer for optimizing the production performance of a well without the need to get involved in the complexities of reservoir modeling.
High-Resolution Permeability Modeling in Highly Heterogeneous Tight-Oil Reservoirs
Authors: Solano N. A. , Soroush M. , Clarkson C. R. , Krause F. F. 
Published: October 2015

Abstract
A high-resolution simulation model of a highly heterogeneous tight oil rock sample is used to investigate the effects of physical and biogenic sedimentary structures on scaling and anisotropy of absolute permeability at the core scale. Results are compared to routine core analysis (RCA) available for similar samples.
The volumetric distribution, quality and connectivity of different contrasting types of elementary flow units [microlithofacies (μLFs)] are individually evaluated for a highly heterogeneous Pembina Cardium lithofacies. Reservoir properties were measured/calculated at a sub-centimeter scale for a core sample using a combination of x-ray computer tomography, pressure decay profile permeability, and image analysis techniques. The derived high-resolution porosity, permeability, and μLFs distribution represents the primary input to a single phase flow model. This model was used to simulate whole-core steady-state tests from which absolute permeability for different orientations was derived. Several simulation sub samples with random location and volume are also selected for evaluation of the effect of scale/composition on the calculated permeability.
The core sample evaluated exhibits three dominant rock types and a bimodal permeability within the microdarcy (μLFs SS2+SH1) and millidarcy ranges (μLFs SS1). The calculated (from whole core simulation) vertical and horizontal permeability values are in good agreement with actual RCA measurements from offset cores. Despite relatively good reservoir quality associated with μLFs SS1, results from the full diameter core simulation demonstrate that its limited volumetric abundance and restricted connectivity prevent this rock type from dominating the fluid flow process in these rocks. In fact, permeability seems to be dominated by the tighter encasing matrix (μLFs SS2 + SH1), which exhibits average permeability values very close to those reported from routine core analysis.
The methodology used in this work is particularly applicable to the detailed characterization of reservoir rocks with high degree of heterogeneity associated with biological reworking and/or selective diagenetic imprints. The model incorporates statistical variations for several key geological/engineering parameters and offers a direct comparison to results obtained from laboratory measurements.
Transient Pressure Behavior for Low Permeability Oil Reservoir Based on New Darcy's Equation
Authors: Hailong Liu , Shuhong Wu 
Published: October 2015

Abstract
With further progress of oilfields development in China, more and more ultra-low permeability oil reservoirs are being put into production. However, in ultra-low permeability oil reservoirs, pore throats are small and the specific surface area is big. Fluid always has a slow seepage velocity and the relationship between the seepage velocity and driving pressure is a curve, not a straight line. Fluid flow in low permeability porous media does not obeys Darcy's law any more, so traditional well testing interpretation methods may cause error in estimation of ultra-low permeability oil reservoir parameters.
This paper describes problems encountered when analyzing transient pressure tests in ultra-low permeability oil reservoir. The equation to describe the non-Darcy's flow was given according to theoretical derivation and experimental method, and three factors were introduced into the equation to improve the Darcy's law. Based on the new model, the theoretical well test model for dual-porosity media in ultra-low permeability oil reservoirs with complex fractures was derived which allows for the influence analysis of non-Darcy's effect. By using Laplace transform and Fourier transform, the model was solved by analytical solution and numerical method. The analytical solution obtained is accurate and simple by contrast numerical method results. Besides, the curves for the pressure responses were plotted. The effects of parameters including fracture width, fracture length and the position of the fracture on the pressure were fully investigated in detail. The advantage of the solution is easy to incorporate storativity ratio and skin factor. It can also reduce the amount of computation and compute efficiently and quickly. Sensitivity analysis shows that non-Darcy flow mainly affects the transition section between the pure wellbore storage and radial flow region, and the pressure derivative curves exhibit a gentle transition region compared with the Darcy's flow. These type curves give a better interpretation of well testing pressure response in ultra-low permeability oil reservoir.
Best Practice and Lessons Learned for the Development and Calibration of Integrated Production Models for the Cooper Basin, Australia
Authors: Mantopoulos A. , Marques D. A. , Hunt S. P. , Ng S. , Fei Y. , Haghighi M. 
Published: October 2015

Abstract
This paper investigates the best practices and lessons learned for both the development and calibration methods of integrated production models. Consequently, this allowed for the successful application of Integrated Production Modeling (IPM) to large scale and complex petroleum production systems in the Cooper Basin, Australia. The potential for calibrated integrated production models to aid the assessment of production system development, forecasting, operational surveillance and optimization opportunities (flow assurance, integrity considerations, well performance/intervention, incremental approaches to development and back out/pressures) supported the need for an optimum (quality versus resource allocated) and innovative development procedure. A structured workflow for developing and calibrating the integrated production models is presented which allows for an improved ability to create and operate such models. The key development components, and for which illustrative and detailed workflows are presented, are: (1) development of reservoir model, (2) development of required well models, (3) development of required surface facility model and (4) the overall calibration of the integrated production model. Detailed within this paper is the extensive theoretical analysis which was mandatory in determining the use of the most suitable parameters which included vertical lift performance (VLP) correlations, flowline correlations, relative permeability curves (generation and alternatives), inflow performance relationship (IPR), water influx models, micro-string implications and all related considerations and assumptions. The paper emphasizes the trade-off between the required outputs from the application of the integrated production models and the available resources and period of development. The value of information is also highlighted through the importance of data collection and preparation procedures, both technical (pressure and fluid) and organizational (procedures). Furthermore, engineering decisions were found to significantly dictate the accuracy and efficiency of the implemented development process and workflows, in particular related to average reservoir properties, cyclic well behavior and the history matching of system pressures and flow rates within the calibration process. The considerations have been supported by relevant examples throughout the paper.
Optimization of Staged-Fracturing in Heterogeneous Tight Gas Reservoirs of Western-Sichuan Gas Field
Authors: He Songgen , Deng Yan , Guo Jianchun , Xiao Yong , Zhao Zhihong 
Published: October 2015

Abstract
Tight gas plays an important role in the increasing production of natural gas. Staged hydraulic fracturing has been a key technology to make recovery of tight gas economically viable. The JP formation of Western-Sichuan Gas Field is a typically tight gas reservoir with horizontal wells. However, the optimization design of staged fracturing encountered two challenges: Low porosity-low permeability with non-Darcy effect; High heterogeneity with discontinuous distribution of sand bodies and properties variation in the longitudinal direction. The traditional optimization method based on Darcy flow and homogeneous model is not capable in the optimization of fracturing parameters (spacing, length and conductivity) and perforation position.
This paper presents a new design method of "one strategy for one well" with better economical results. Firstly, non-Darcy flow character was measured by laboratory displacement experiment. The relationship between pseudo threshold pressure gradient (pseudo TPG) and permeability was fitted based on quasi-linear flow with pseudo TPG. Secondly, long horizontal section heterogeneous reservoir models were built on the basis of log and geological interpretation, which involves homogeneous continuous model, interbedding model with barrier and heterogeneous model composed of different seepage units. With barriers and seepage units located, fracture parameters include fracture spacing, length and conductivity were optimized for the goal of best economical production with numerical simulation. Thirdly, a model of induced stress from hydraulic fractures was established based on displacement discontinuity theory. Combined with the optimal fracture spacing, the best perforation position was located with the target of low initiation pressure. Lastly, based on fractures parameters and perforation positions, the operation parameters are designed.
The new design method has been successfully applied to 21 horizontal wells with staged fracturing. Microseismic fracture mapping is conducted to evaluate fractures geometry. The results of post-fracture analysis and post-production evaluation demonstrate the benefits of this new optimization method.
Mud Filtrate Invasion and Wireline Formation Tester Cleanup Performance: Modelling and Field Case Study
Authors: Kass S. , Ellis E. , Pourabed H. , Maleki E. , Schumacher G. , Zeinijahromi A. 
Published: October 2015

Abstract
A new generation Wireline Formation Tester (WFT) was used to perform fluid sampling in a subject field as part of an appraisal drilling campaign targeting significant undeveloped conventional oil reserves. The field consists of free gas caps with associated saturated oil intervals that appear as thin rims around anticlinal flanks. Resistivity log analysis predicated a mud filtrate invasion volume of 89L. Approximately 150% of the expected invasion volume (128L) was pumped during sampling. Laboratory results showed that the sampled fluid was still mud filtrate, despite pumping an extra 50% of the estimated volume required for hydrocarbon breakthrough.
This paper presents a mathematical model for predicting filtrate invasion and post drilling WFT cleanup performance. A new methodology is developed to incorporate critical shear stress concepts into mud filter-cake thickness and filtrate invasion calculations. The mathematical model is used to provide input data for Eclipse reservoir simulator (E100) and an analysis of the field case. The model can also be applied as a predictive tool for filter-cake development, filtrate invasion and pump-out volumes required during fluid sampling. In addition, the model can be used to design optimal mud properties that minimize filtrate invasion and extra treatment of the invaded zone post-drilling. The mathematical model is integrated with reservoir simulation to model the cleanup process.
The mathematical model developed in this study predicted an invasion volume of 528L, which is significantly greater than what was estimated based on resistivity logs (89L). This implies that filtrate invasion volume in the field case was underestimated. A sensitivity study showed that filter-cake permeability was the greatest determinant of filtrate invasion volume, and that radius of filtrate invasion was the greatest control on mud filtrate cleanup during sampling. Reservoir simulation provided a good match between model simulation results and field data.
Experimental Analysis of ESP Performance in Pipe Flows Including Methane Hydrate
Authors: Shimizu T. , Yamamoto Y. , Tenma N. , Narita H. 
Published: October 2015

Abstract
Centrifugal pump performance of electric submersible pump (ESP) is analyzed experimentally during emulsification process in methane-water pipe flows. The ESP is installed in a horizontal pipe section of a flow loop. The flow loop is placed vertically with the total length of 10.4 m, which is composed of the stainless steel pipeline of 2.1 cm inner diameter and the upflow test section of 5 cm inner diameter. The system temperature is kept isothermally at 4 °C and the initial gas-phase volume fraction is fixed at 0.016 while the pump speed and the flow rate are varied up to 2500 rpm and 50 L/min, respectively. The flow regime of the initial gas-liquid flows is determined to be turbulent bubbly flows. Transformation of vapor methane into solid methane hydrate is made by elevating the system pressure up to the super cooling condition through water injection. The detail emulsification process is characterized with use of a high speed camera and in-situ particle size analyzer, both of which are located at the pump downstream. The particle size analyzer employs the focused beam reflectance measurement (FBRM) technique.
It is found that the extent of phase transformation is limited by the pump speed as it determines the smallest size of bubbles generated in the flow line. Emulsion is appeared to be white-opaque, which is made by clouds of microbubbles encapsulated by methane hydrate. The opaque particles can be detected by FBRM and exhibit uniform size distributions, indicating that the particles are emulsified homogeneously in the entire flow domain through fragmentation and coagulation kinetics. The majority of methane hydrate particles are appeared to be transportable by the bulk fluid though some particle deposition on the viewing glass window can be occurred. Higher water power is given by the ESP under the emulsified flows than that of water-only flows, indicating that the apparent fluid viscosity can be increased by methane hydrate particles emulsified in water solution.
Improving the Wellbore Stability While Drilling Long Open Hole Shale Intervals in Tahe Oil Field
Authors: Zhong Hanyi , Qiu Zhengsong , Chen Ganghua , Huang Weian , Dong Bingqiang , Zhang Daoming , Fu Jianguo , Tong Shiquan 
Published: October 2015

Abstract
In order to accelerate the drilling speed and reduce the drilling cost, the well structures were simplified in Tahe oil field in recent years. As a result, the length of open hole section increased dramatically, even as high as 4700m for some wells, and different formations including active shales, gypsum, and limestone were encountered in the drilling process. Drilling in such long interval of open hole undertook the risks of cavings, stuck pipe, hole enlargement, lost circulation and so on because of the complex formation and changing pressure gradients. Therefore, highly inhibitive water-based drilling fluids were essential to improve the wellbore stability of the challenging sections.
To understand the mechanisms of shale-drilling fluid interactions when exposed to water-based drilling fluids, the morphology and mineralogy of shale samples were characterized via scanning electron microscope (SEM) and X-ray analysis. Meanwhile, inhibitive evaluation methods such as swelling test, dispersion test and cation exchange capacity (CEC) test were carried out to analyze the interaction potential of shale samples from the open hole intervals. The results indicated that for the upper interbedded sandstone and shale formation, impressive content of clay minerals (mainly smectite) and weak bonding were contributed to the high potential of swelling and dispersion. While for the deep brittle shale formations, the content of clay mineral (mainly illite and illite/smectite) was also relatively high, and micro-fractures were observed, which provided the access of water invasion.
After analyzing the wellbore instability mechanism of the open hole interval, different drilling fluid strategies were proposed according to the reactivity of formations. For shallow formation, polyamine polymer water-based drilling fluid was selected to suppress the hydration and dispersion of reactive shales. While for the deep formation, polyamine and sulfonated polymer water-based drilling fluid was optimized, in which polyamine as shale hydration inhibitor, sulfonated asphalt and superfine calcium carbonate as microfracture sealing agent were used in combination to realize the chemical and physical stability of brittle shales.
The optimized inhibitive water-based drilling fluids in laboratory were successfully transferred to the application in the long open hole intervals of Tahe oil field. The field application in this area resulted in reduced cost, improved gauge hole and reduction in total NPT. No complicated problems occurred in the field trial. The application indicated that elaborately designed drilling fluids reached satisfying results.