bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Full Field Downhole Foam Assisted Lift Application For Enhance Gas Recovery
Authors: Rahman Risal , Poirault Dominique , Warsito Sandy , Martin Serge , Shook Richard 
Published: October 2014

Abstract
Total E&P Indonesie (TEPI) is the main gas producer in Indonesia which produces around 1900 MMscf/d of gas. One of the challenges is to maintain its production plateau under liquid loading issue. Almost half of TEPI gas production comes from liquid-loaded wells, representing 85% of total producing wells in the affiliate.
Up until recently, dewatering activity in TEPI is only performed by means of regular offloads; involving substantial means. These operations present specific risks not only for safety and assets but also for environment by flaring of gas through testing barge.
A cross functional team has been established to find out innovative solution based on the "Foam Assisted Lift" (FAL) principle and enabling to keep existing DHSV in the well completion. The FAL principle consists in offloading the wells by creating foam down-hole through continuous injection of surfactant to help liquid lifting and gas breakthrough.
This paper describes Capillary String Injection System that can be fitted into existing wells, using existing DHSV control line for surfactant injection while keeping its primary safety function as a fail-safe device. The installation equipment includes a modified wireline-retrievable surface-controlled sub-surface safety valve (WR-SCSSV) with capillary tubing attached below it. Injection operates via existing control line of the safety valve to inject chemicals, does not require any further wellhead modification. In addition, this system fits perfectly with the context of mature field; simple, cost-effective, safe and easy to handle.
Experimental Evaluation of Models for Calculating Shear Rates of Polymer Solution in Porous Media
Authors: Sun Wenjie , Li Kewen 
Published: October 2014

Abstract
One of the difficulties of characterizing polymer flooding comes from the non-Newtonian and time-dependent properties of polymer solutions, and shear rates must be determined to calculate the viscosity of polymer solutions flowing in porous media. Although there have been many models to do so, it is still difficult to choose which shear rate model to conduct the calculations. In this study, several polymer flooding experiments were designed and conducted in rock samples with different permeabilities to evaluate the models for determining shear rates of polymer flooding in porous media. Experiments were also conducted in simple glass capillary tubes to reduce the effect of polymer adsorption on the evaluation. Four frequently-used shear rate models for porous media were chosen to be evaluated. Using the experimental data, the values of shear rate of the four models were computed respectively, as well as the pseudopermeability of the core samples under single-phase flow but different flow rates. The best shear rate model among the four frequently-used models was determined, and the rule of making the judgments was proposed and verified, that is, the pseudopermeability at the intrinsic shear rate should be equal or close to the absolute permeability of the sample in the cases of capillary tubes.
Effect of Natural Fractures on Eagle Ford Shale Mechanical Properties
Authors: Hu Dandan , Matzar Luis , Martysevich Vladimir 
Published: October 2014

Abstract
Natural fractures widely exist in shale samples, and natural opening-mode fractures reactivate during stimulation and enhance efficiency by widening the treatment zone. The existence of natural fractures is very important to the stimulation treatment and will eventually benefit the shale gas/oil reservoir recovery. The effect of natural fractures on a shale mechanical property study will serve as the basis for the formation evaluation and the sweetspot selection on the hydraulic fracturing treatment. By combining conventional destructive mechanical tests and novel digital rock nondestructive analysis, important conclusions can be determined regarding the mechanical properties changing trend as a function of the fracture structure. The more complex the natural fracture structures, the less resistant the rock. This paper presents, in detail, the changing trend from various shale samples.
Studies on the mechanical properties of Eagle Ford shale samples (e.g., Young's modulus, Poisson's ratio, etc.) are performed in a laboratory using a hydraulic load frame, and the core internal fractures are computed tomography (CT) scanned before and after the mechanical tests. The effect of natural fractures on the mechanical properties is analyzed through the testing data. The induced fractures are characterized in several Eagle Ford shale core plugs in terms of orientation, size, and width. Substantial image processing techniques are employed to analyze the three-dimensional (3D) rock microstructures. The statistical properties, such as the width, length, and the tortuosity of the main fractures, are obtained through image analysis. The volume of the fractures and the permeability on all x, y, and z directions on the central part of the core plug are calculated based on the 3D CT images as well. The small fractures can serve as the planes of weakness and reactivate during a hydraulic fracture treatment.
This paper elaborates on the data interpretation and measurement correlation methods used to study natural fracture behavior as well as how this behavior affects mechanical tests, which can be very important in the field of geomechanics as well as formation stimulation research.
Multiphase Flow Modeling of Surface Equipment in Managed Pressure Drilling Operations
Authors: Deshpande Kedar M , Northam Paul , Sabhapathy Peri , Gandikota Raju , Ring Lev 
Published: October 2014

Abstract
Surface equipment for Managed Pressure Drilling operations handles a multiphase mixture of drilling mud, cuttings and reservoir fluid influx. It is mandatory for safe MPD operations that surface equipment be able to handle pressure surges, pressure drops as well as any phase change of the fluid without causing any safety issues. In MPD operations, the surface choke is a key surface manifold component through which the fluid passes before entering the measurement gauges or solids control processing. Depending on choke position and flow conditions, part of the fluid can change phase from liquid to gas as it flows through the chokes resulting in formation of a gaseous phase that can be problematic for the downstream flow measurement devices and equipment integrity. A detailed analysis of the phase transition of the fluid in the surface equipment is necessary that can elucidate design modifications to ensure accurate measurements for safe and efficient drilling operations.
In this work, multiphase fluid flow is analyzed numerically using 3-D computational fluid dynamics (CFD) and a 1-D hydraulics network solver to understand the effects of choke positions on the overall pressure drop, pressure surges and onset of phase transformation to ensure surface equipment safety. 1-D hydraulics network results are validated against the 3-D CFD software as well as against experimental studies. Based on extensive numerical 1-D studies, look-up tables and charts were developed that help field personnel design the best surface equipment configuration, determine associated pressure drop and guard against the possibility of phase transformation.
Good Things Come in Little Packages: Nanotechnology for Reduction in Pore Pressure Transmission
Authors: Moroni L. P. , Vickers S. , Gray C. , Davidson M. 
Published: October 2014

Abstract
An increasing number of wells are being drilled in formations with a high risk of well bore instability. Historically, the majority of instability was a result of drilling reactive clays with water-based fluids. This is still a common risk and is usually addressed by using oil- and synthetic-based fluids. However, we now more commonly have to overcome the problems associated with drilling depleted or weak formations which can be difficult to drill even with oil- or synthetic fluids. This is especially common in fields that have been producing for many years and where geological pressures have been altered. More and more often, stress caging techniques are being used to drill these unstable formations. Effective stress caging is relatively straight forward if all the parameters are known; however, this is rarely the case and accurate fracture and pore throat measurement in-situ is nearly impossible. To seal these fractures, which are sometimes a few microns or less, a new form of micro- or nano-sized sealant is required in addition to the conventional calcium carbonate/graphite particle blend.
This paper presents a novel drilling fluid additive that utilises particles of approximately 200nm to seal fractures and pores to stop the invasion of drilling fluid filtrate and reduce pore pressure transmission. This enables wells to be drilled in depleted formations without losses, use very high overbalances with no differential sticking, and also plug micro pores and micro fractures found in shales to reduce instability and improve hole integrity. Laboratory testing is described that demonstrates the advantages of using this technology and case histories proving its usefulness in the field are described. Utilisation of this new nanotechnology will enable many problematic formations to be drilled safely and trouble-free by reducing the risk of wellbore failure.
Refinement of Relative Permeability Measurements by Accounting for Viscous Fingering in Coreflood Experiments
Authors: Pereira B. , Shahverdi H. , Sohrabi M. 
Published: October 2014

Abstract
Relative permeability (kr) is a critical input data for any calculation involving multiphase flow in petroleum reservoirs. Normally, kr curves are obtained by performing coreflood experiments as part of SCAL measurements or EOR studies. The results of the experiments are then used to obtain kr values often by either analytical models (e.g. JBN) or 1D history matching techniques. These models are based on the Buckley-Leverett displacement theory, which is not applicable to unstable displacements.
In this paper, we present a simple method to calculate the relative permeability from coreflood experiments in which the displacement front could be unstable, for instance due to adverse viscosity ratio. The method proposed here modifies the JBN technique, and hence is referred to as modified JBN (MJBN), by including a viscous fingering term (η) in the oil fractional flow. In order to calculate η, we have developed a correlation between the viscosity ratio and the displacing fluid's viscosity. The correlation was obtained by producing viscous fingering with a known relative permeability and an unfavorable viscosity ratio. The relative permeability obtained by this method was then compared with the results obtained using history matching by commercial software widely used in laboratories.
The results show that η is function of viscosity ratio and displacing fluid viscosity. This means that η can be used for a wide variety of cases, with different kr, core properties or fluid properties, just by using the same plots of η versus viscosity ratio versus displacing fluid viscosity to estimate η. 1D history matching was compared with modified JBN (MJBN) for an experiment with unstable flow, resulting in a considerably better match using MJBN.
This work provides new insights into the often overlooked issue of viscous fingering, its impact on multiphase flow, and a simple way of correcting kr data for the adverse effects of viscous fingering in kr measurement experiments. The proposed method can be easily adapted by service companies and researchers interested in measuring relative permeability in order to improve the quality of measurements and the accuracy of this crucial data.
New Method for Determining Mineralogy and Matrix Properties from Elemental Chemistry Measured by Gamma Ray Spectroscopy Logging Tools
Authors: Freedman R. , Herron S. , Anand V. , Herron M. , May D. , Rose D. 
Published: October 2014

Abstract
Methods for predicting mineralogy from logging tool measurements have been an active area of research for several decades. In spite of these efforts, methods for predicting quantitative mineralogy including clay types from well logging data were not fully achieved. The introduction of geochemical logging tools in the 1980s offered promise; however, early versions of geochemical logging tools did not measure elemental chemistry with enough accuracy and precision to enable reliable and quantitative determination of mineralogy. Recent advances in geochemical logging tool technology now enable accurate and robust measurements of the chemical elemental concentrations that are needed to determine continuous quantitative and detailed logs of mineralogy.
This paper presents a novel approach for determining more accurate, detailed mineralogy from an elemental spectroscopy logging tool. This work was made possible by three recent developments: the introduction of a new high-performance neutron-induced gamma ray spectroscopy logging tool, a new high-quality research database consisting of chemistry and mineralogy measured on cores acquired worldwide from conventional and unconventional reservoirs, and a new model-independent inversion method that overcomes the limitations of previous model-dependent methods.
The model-independent inversion makes use of the database which includes clean sands, shaly sands, shales, carbonates, and complex mixed lithologies. The database contains laboratory measurements of dry-weight elemental chemistry and mineralogy measured by transmission Fourier transform infrared spectroscopy. The database is used to derive a model-independent mapping function that accurately represents the complex functional relationship between the elemental concentrations and the mineral concentrations. Once the mapping function is determined from the database, it can be used to predict quantitative mineralogy from elemental concentrations derived from the logging tool measurements. Unlike previous inversion methods, the model-independent mapping function does not have any adjustable parameters or require any user inputs such as mineral properties or endpoints.
The mapping function is used to predict continuous logs of matrix densities plus concentrations of 14 minerals (i.e., illite, smectite, kaolinite, chlorite, quartz, calcite, dolomite, ankerite, plagioclase, orthoclase, mica, pyrite, siderite, and anhydrite) from eight dry-weight elemental concentrations derived from the logging tool. The new method has been applied to well log data acquired worldwide in numerous conventional and unconventional reservoirs having a wide variety of complex mineralogies. The predicted mineralogies and matrix densities are generally found to be in good quantitative agreement with core-derived mineralogies and matrix densities.
Secondary Application of Low Salinity Waterflooding to Forties Sandstone Reservoirs
Authors: Law S. , Sutcliffe P. , Fellows S. 
Published: October 2014

Abstract
Low salinity waterflooding (LSWF), versus high salinity waterflooding (HSWF) has been the focus of significant research at various centres around the world, yet there is still considerable debate over the exact mechanism that provides incremental oil recovery. The use of the LSWF technique is not widespread in the United Kingdom continental shelf (UKCS). However, it has been announced that the Clair Ridge development will deploy low salinity waterflooding (LSWF) in secondary mode from the start of field life, and a number of companies are currently assessing the applicability of the technique through high level screening and core flooding. Forecasting the potential oil recovery under LSWF is heavily influenced by the simulation technique that is used. Presently the most widely discussed approach is the use of a weighting table with relative permeabilities representing the high and low salinity cases. As the grid block falls below threshold salinity, the simulator utilises the weighting table to assign an interpolated value of salinity. This value of salinity is utilised to represent a change in wettability. While this approach approximates the net effect of LSWF, it does not capture the oil/rock/brine interaction. This study examines the modelling approach to LSWF utilising an in-house generic Forties Palaeocene model in CMG's STARS simulator. The conventional approach of modelling LSWF using high and low salinity relative permeabilities is compared to the latest Multi-component Ion Exchange (MIE) methods by numerical simulation to assess the impact on incremental oil recovery. A sensitivity analysis is then carried out on the effects of specific parameters on incremental oil recovery, utilising published data from fields in the Forties Palaeocene fan system. A discussion is provided. The impact on secondary recovery was accessed with respect to wettability alteration; injection salinity (LSWF versus HSWF); oil viscosity and aquifer influx. The application of LSWF in secondary mode to the Forties Palaeocene Sandstones was found to be favourable for the case of mixed-wet reservoirs.
Case Studies: The Ensemble-Based Approach to History Matching and Model Parameter Estimation
Authors: Zhang Yanfen , Bhark Eric , Phale Hemant A. , Dehghani Kaveh 
Published: October 2014

Abstract
Multiple assisted history matching (AHM) techniques commonly applied in the oil and gas industry were benchmarked for their applicability to field studies. The benchmarking effort was aimed at exploration of the theoretical as well as practical benefits, challenges and tradeoffs of the AHM techniques as they are utilized for asset development and reservoir management.
This paper specifically discusses benchmarking of ensemble-based methods as applied for history matching of a key deepwater asset for the corporation. Two variations of ensemble-based methods are examined: the ensemble Kalman filter (EnKF) (Evensen, 2009) and the ensemble smoother with multiple data assimilation (ES-MDA) (Emerick and Reynolds, 2013). In both techniques, the ensemble of parameter estimates evolves as field data are assimilated into the reservoir characterization, either sequentially using the EnKF or iteratively using the ES-MDA. Both of these variations have been deployed with adaptive bootstrap-based screening (Zhang and Oliver, 2011) to reduce the sampling error of ensemble estimates.
One significant strength of ensemble-based methods is their ability to estimate high-resolution model parameters. In this benchmark study, however, the ensemble-based methods were applied for estimation of a group of low-resolution model parameters including regional property multipliers and pilot points. The insights gained from the inverse problem of constraining reservoir simulation models to historical production data can be particularly valuable in guiding the practitioner in re-definition of the prior model uncertainty and towards the model solution. The study shows that a major challenge in the application of ensemble-based methods is parameter over-adjustment resulting from the improper addition of observation errors associated with the actual observations. In practice, multiple experiments are required for the user to iteratively improve the optimal level of the added errors. As the number of observations grows large, the increase in computational cost and decrease in ensemble variability are additional challenges in the application of ensemble-based methods. While assimilating different types of data, a balanced proportion of these data types should be maintained. These points are illustrated and discussed in the field application section of the paper.
Pressure Transient Analysis as an Element of Permanent Reservoir Monitoring
Authors: Shchipanov A. A. , Berenblyum R. A. , Kollbotn L. 
Published: October 2014

Abstract
Pressure transient analysis (PTA) is traditionally used to characterize well and reservoir parameters from well tests based on shut-in periods. PTA was widely used for reservoir management and decision making before reservoir simulation became the main tool. Presently more and more reservoirs are surveyed by permanent (downhole) gauges. These gauges provide vast amount of pressure transient and rate data which may be interpreted using improved PTA approaches to gain more knowledge on reservoir dynamics. This has opened new prospects for PTA applications in field studies.
Permanent pressure and rate measurements cover both well flowing and shut-in periods occurring during normal operations. These measurements allow for analysis of time-lapse pressure transients and comparative interpretation of flowing and shut-in periods. The analysis of time-lapse data provides time-dependent description of well-reservoir parameters. The comparative interpretation gives understanding of flowing reservoir properties which are often different from those estimated from well shut-in periods as in the classical PTA. These approaches provided basis for an improved methodology of interpreting permanent pressure measurements, where the scope of the standard PTA application may be extended to integrate new data sources.
Application of the developed methodology has been demonstrated with data from fields on the Norwegian Continental Shelf. For many wells the comparative interpretation revealed significant difference in well-reservoir parameters estimated from flowing and shut-in periods. It was also found that the flow regime near a well may vary. For example, the dominance of a hydraulic fracture observed during a shut-in period may be significantly reduced during the flowing period with simultaneous changes in reservoir conductivity. Dynamic behavior of natural and induced fractures due to pressure (stress) changes, wellbore cross-flows and variable contribution of reservoir layers are considered to be possible reasons for these effects. Analysis of time-lapse pressure transients provided description of long-term changes in well-reservoir parameters, e.g. reservoir conductivity, hydraulic fracture properties and boundary effects.
The key advantage of applying this methodology is characterization of the more representative flowing, rather than shut-in, well-reservoir parameters as well as their permanent monitoring during reservoir lifetime. The monitoring may reveal ongoing changes in the reservoir characteristics, production impairment risks etc. The methodology uses data readily available for many fields and provides an updated description of well behavior and hydraulic reservoir properties. The reward may be improvement in everyday field operations and well performance optimization, reduced uncertainty of input to reservoir models and better decision making through enhanced model predictability.