bluuebunny/crossref_metadata_2025_split huggingface dataset:
ESP Operation, Optimization, and Performance Review: ConocoPhillips China Inc. Bohai Bay Project
Authors: Jiang Zhizhuang , Zreik Bassam 
Published: February 2020

SPE Gulf Coast Section Electric Submersible Pump Workshop, The Woodlands, Texas, 25–27 April, 2007

Abstract
ConocoPhillips China Inc. (COPC) operates the Penglai 19–3 oil field, located offshore in Bohai Bay, the People's Republic of China. COPC holds a production sharing agreement with China National Offshore Oil Corporation(CNOOC). The Penglai 19–3 field is the second largest oil field in China with 3.8 billion bbl of oil in place, discovered in May 1999 and put on productionin December 2002.
Electrical submersible pumps (ESPs) were selected as the most economic artificial lift method to develop the field, based on the reliability, flexibility and robustness to produce wells with high flow rates and lift heavyoil in an offshore environment.
The first ESP installations were challenged with high free gas and excessives and production, resulting in operational issues and a number of failures. Even in this hostile environment, production peaked at 37,800 BOPD during November 2003, before declining as a consequence of reservoir pressure depletion. Moreover, the lower reservoir pressure increased the free gas, thereby reducing pump performance, excessive sand production lead to plugging of the pumping system and sand fill across the reservoir reduced productivity.
Various enhancements to the completion and ESP system were made during subsequent well interventions improving ESP performance, maximizing and maintaining production from the field. Furthermore, performing continuous ESP data trend analysis and performance modeling enabled the artificial lift system to be analyzed and diagnosed to maintain optimum well performance. Collaboration between Operator and Service Provider through performance review meetings and changes to operational practices were also implemented.
This paper reviews the operation, optimization, and performance of the ESP systems and the challenges faced during the first 3 years of production. Covering initial installations, subsequent well interventions, operation philosophy, optimization methodology, case studies demonstrating value of gas separation and handling devices, completion improvements, ESP configuration enhancements, run life assessment and equipment dismantle findings.
Carbon Dioxide Solvent Flooding for Increased Oil Recovery
Authors: Holm L.W. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 216, 1959, pages 225–231.

Abstract
Laboratory flooding experiments on linear flow systems indicated that high oil displacement, approaching that obtained from completely miscible solvents, can be attained by injecting a small slug of carbon dioxide into a reservoir and driving it with plain or carbonated water. Data are presented in this paper which show the results of laboratory work designed to evaluate this oil recovery process, particularly at reservoir temperatures above 100F and in the pressure range of 600 to 2,600 psi. Under these conditions CO2 exists as a dense single-phase fluid.
It was found that a bank, rich in light hydrocarbons, was formed at the leading edge of the CO2 slug during floods on long cores. Formation of this bank is probably due to a selective extraction by the CO2 and, it is believed, partially accounts for the attractively high oil recoveries. In addition to the efficient displacement of oil from the pores of the rock by this process, the favorable mobility ratio related to a CO2-water flood also contributes to high oil recovery. A further advantage of this process is noted on limestone and dolomite rock, in that the CO2 reacts with the porous medium increasing its permeability.
Flooding experiments were conducted on sandstone and vugular dolomite models. The results of this experimental work show the effect on oil recovery of type of porous medium, pore geometry, flooding length, and flooding pressure. The porosity of the cores and models varied from 16 to 25 per cent and their permeabilities ranged from 100 to 200 md. A reconstituted West Texas reservoir oil, a West Texas stock tank oil, an East Texas stock tank oil and Soltrol were used to represent reservoir oils in this study. Oil recoveries ranging from 60 to 80 per cent of the original oil in place in these cores were obtained by CO2-carbonated water floods at pressures between 900 and 1,800 psi, compared with conventional solution gas drive and waterflood recoveries of 30 to 45 per cent on the same cores. Oil recoveries greater than 80 per cent resulted from floods at pressures above about 1,800 psi. These high recoveries were noted from both the sandstone and the irregular porosity carbonate cores.
Experimental Aspects of Reverse Combustion in Tar Sands
Authors: Reed Ronald L. , Reed Denzel W. , Tracht Joseph H. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 99–108.

Abstract
Laboratory experiments on the reverse combustion of tar sands in a linear adiabatic system have shown that a highly upgraded oil can be produced from an exceedingly viscous, immobile oil.
The dependence on the air-injection rate of peak temperature, combustion-zone velocity, oil recovery, air-oil ratio, residual coke and oil, fuel burned and distribution of product gases is shown graphically. Effects of initial temperature, oxygen concentration, oil saturation and heat loss are discussed. Experiments bearing on the coking properties of heavy oils are mentioned and some results exhibited.
Field application of the process hinges on the existence of adequate air permeability and the rate of reaction under reservoir conditions.

Introduction
It has been established that oil can be recovered from underground reservoirs by means of at least two fundamentally distinct methods involving in situ combustion of a certain fraction of the oil. Characteristic of both of these known methods is the production of oil from one or more wells by means of hot gases formed when a high-temperature reaction zone is advanced through the reservoir. In both cases, the reaction zone is created by heating certain of the wells to a sufficiently high temperature prior to the introduction of air, and the zone is maintained and advanced through the reservoir by appropriate control of the air-injection rate.
In the first of these methods, which is called "forward combustion", the combustion zone advances in a direction which is generally the same as that of the air flow; whereas in the second method, "reverse combustion", the combustion zone moves in a direction generally opposite to that of the air flow.
Forward combustion, on the one hand, is an ideal combustion process in the sense that a minimum of the most undesirable fraction of the oil is consumed as fuel in the form of coke, a clean sand is left behind and generated heat is used as efficiently as possible. However, the applicability of forward combustion is limited. Since the products of combustion, vaporized oil and connate water must flow into relatively cold regions of the reservoir, there is an upper limit on the viscosity of oil which can be moved by this process in a practical and economical fashion.
Theoretical Considerations of Reverse Combustion in Tar Sands
Authors: Warren Joseph E. , Reed Ronald L. , Price Harvey S. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 109–123.

Abstract
The behavior of the reverse-combustion process in a linear adiabatic system is theoretically investigated by means of an idealized physical model. This model is described by a pair of non-linear equations involving heat and mass transfer which are coupled by a concentration-dependent reaction-rate function of the Arrhenius type.
The differential equations governing the quasi steady-state temperature and concentration distributions are approximately solved by using either physical or mathematical simplifications. It is shown that the reverse-combustion process can be mechanistically described by simple physical models whose behavior equations can be solved formally. It is further demonstrated that the derived reverse-combustion equations can be solved numerically within the error limits for the experimental data. The theoretically predicted peak temperature-flux-velocity relationship exhibits reasonable agreement with experimental data obtained from Athabasca tar sand.
The principal contribution of this work lies in its usefulness as a starting point for developing a more comprehensive theory. A description of the vaporization-coking process must be obtained; then, the theory must be extended to three dimensions to include geometrical effects and heat losses.

Introduction
In another paper, the physical processes visualized as occurring during reverse combustion have been described. In this paper, the extent to which an elementary theory can account for experimental observations is determined. Theoretical results that can be used to estimate some of the behavior characteristics of importance to this process are also presented.
Since it is not possible to include all the features of the combustion mechanism of which we are currently aware, the mathematical formulation refers to the highly idealized system developed herein. This simplified physical model is based on the simultaneous transfer of mass and heat accompanied by a chemical reaction; it is described mathematically by a pair of coupled, nonlinear differential equations. Similar sets of equations have been studied extensively in the field of flame propagation; an excellent review of these investigations has been published by Evans.
Miscible Displacement - Flow Behavior and Phase Relationships for a Partially Depleted Reservoir
Authors: Wilson J.F. 
Published: February 2020

Published in Petroleum Transactions, AIME, Vol. 219, 1960, pages 223–228.

Abstract
An experimental investigation has been made of gas-driven slug displacements in a system of high gas saturation to evaluate the process for use in a California reservoir. Fluid compositions, temperature, pressure and core permeability duplicated reservoir conditions as closely as possible. The temperature was above the critical of the slug materials. The slug composition required for 100 per cent oil recovery in the linear flow systems was found to agree with that determined from equilibrium phase studies.
A qualitative theory for the slug displacement of two-phase systems is proposed and found to be in general agreement with the observed flow behavior. The theory predicts that the length of the reservoir fluid slug transition zone will increase with increased initial gas saturation and decrease with increased oil swelling accompanying the composition change from reservoir oil to the critical composition.
The precipitation of small amounts of an asphaltic phase during the formation of the transition zone had no adverse effects on the Yow behavior of otherwise miscible systems.

Introduction
Despite the large number of recent publications relating to oil recovery by miscible displacement, little information is available concerning the behavior of crude oil-natural gas systems at conditions likely to be encountered in field application. The laboratory data reported here were obtained during an investigation of the possibility of using a gas-driven LPG slug in a partially depleted California reservoir. Seven gas-driven slug displacements employing slugs of different compositions and sizes were made in 26- to 27-ft long sandstone cores. The equilibrium phase behavior of the systems was also determined.
Displacement of Oil by Rich-Gas Banks
Authors: Arnold C.W. , Stone H.L. , Luffel D.L. 
Published: February 2020

Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 305–312.

Abstract
The purpose of this research is to determinethe efficiency of small banks of enriched gas driven by methane in displacing oil from a porous medium andthe effects of variation in bank size and composition of that efficiency.
Most of the experiments were conducted in a sand-packed tube 20-ft long and 1/2-in. in diameter. The hydrocarbon system generally used was methane, butane and decane at 2,500 psia and 160°F.
The results of these experiments indicate that, in the regions contacted by the gas, a small bank of an oil-miscible gas driven by methane can displace all of the oil in a piston-like manner. If the enriched gas is of such composition as to remain immiscible with the oil, displacement of oil is less efficient than for the miscible case, and the gas hank travels through the sand with a velocity less than that of the driving gas.
These data along with theories discussed imply that smaller banks and less total gas are required when the enriched gas and oil are miscible.

Introduction
Widespread application of enriched-gas drive to the recovery of oil rests upon a key factor the use of limited quantities, or "banks", of enriched gas. At the present time, the value of liquefied petroleum gas or other enriching agents discourages their use in a continuous injection technique, or even in a large bank, except in a few isolated reservoirs. If small banks of enriched gas driven by methane were as effective in displacing oil as is continuous injection, the enriched-gas drive process might be applied to a larger number of reservoirs.
Previous research on the mechanics of the enriched-gas drive process reported by Stone and Crump and by Kehn, Pyndus and Gaskel has utilized continuous injection of enriched gas. This work has shown that two types of displacements occur. With gases containing sufficient intermediates, the oil is displaced miscibly and complete recovery is obtained from the regions swept. When gases are used which contain insufficient intermediate hydrocarbon for miscible displacement, oil is displaced immiscibly. In the latter type, selective solution of the intermediate hydrocarbons causes a swelling and reduction in viscosity of the oil and leads to an increased recovery over that obtained by dry-gas (methane) drive.
The Efficiency of Miscible Displacement as a Function of Mobility Ratio
Authors: Habermann B. 
Published: February 2020

Published in Petroleum Transactions, AIME, Vol. 219, 1960, pages 264–272. Paper presented at 35th Annual Fall Meeting of SPE, Oct. 2–5, 1960 in Denver, and at the California Regional Fall Meeting of SPE, Oct. 20–21, 1960 in Pasadena, Calif.

Abstract
Artificially consolidated sand models, representing one-quarter of a five-spot, have been developed and used to study factors affecting miscible displacement. Sweep efficiency at breakthrough, size of the mixing zone between two miscible liquids and per cent are contacted by drive after breakthrough were determined for the high mobility ratios encountered in actual reservoirs. Quantitative relationships between the degree of viscous fingering and mobility ratio were obtained by measuring the length of the fluid interface.
Scaled miscible-slug experiments, supported by field evidence reported in the literature, have shown that when the slug is followed by dry gas the process is less efficient than expected. In addition to low areal sweep efficiencies encountered for high mobility ratio displacements, the effectiveness of a miscible slug is greatly reduced. This is caused by an accelerated growth of the mixing zone between the driving and the displacing fluids.

Introduction
Considerable interest in miscible displacement as a secondary recovery process has been shown by the oil industry in recent years. In addition to extensive laboratory investigations, numerous field operations have been initiated so that 39 miscible displacement projects had been reported in the United States by early 1959. By far the most popular approach in these projects is the use of an LPG slug followed by dry gas.
Multiscale Modeling of Gas Transport in Shale Matrix: An Integrated Study of Molecular Dynamics and Rigid-Pore-Network Model
Authors: Wang Sen , Feng Qihong , Javadpour Farzam , Zha Ming , Cui Ronghao 
Published: February 2020

Summary
The physics of gas transport through shale systems remains ambiguous. Although several theoretical and experimental studies have been reported, most concentrate only on the permeability of shale kerogen. Shales, however, are composed of various proportions of organic matter and inorganic minerals (e.g., calcite and clay). Inorganic pores are larger than organic pores, thus affecting apparent permeability. To accurately predict the apparent permeability of shale, we couple molecular dynamics (MD) and a pore-network model (PNM) to develop a multiscale framework for gas flow through shales. First, we use nonequilibrium MD (NEMD) to study the pressure-driven flow behavior of methane (CH4) through organic, calcite, and clay [montmorillonite (MMT)] nanopores under reservoir conditions, from which, using the slip-corrected Poiseuille equation, we propose a mass-transport model accounting for the contributions of both the adsorbed-phase fluid and bulk fluid. Then, we incorporate these formulations into a shale PNM in which the influences of shale composition and bimodal pore-size distribution (PSD) are taken into account. We also develop an analytical model for the apparent permeability of shale matrix using the bundle-of-capillaries approach. In comparison with previous methods, our proposed models highlight the effect of relatively greater pore sizes in inorganic matrices. This work provides an efficient tool for better understanding gas transport through shale systems at both molecular and pore scales.
Using Machine Learning Methods To Identify Coal Pay Zones from Drilling and Logging-While-Drilling (LWD) Data
Authors: Zhong Ruizhi , Johnson Raymond L. , Chen Zhongwei 
Published: February 2020

SummaryAccurate coal identification is critical in coal seam gas (CSG) (also known as coalbed methane or CBM) developments because it determines well completion design and directly affects gas production. Density logging using radioactive source tools is the primary tool for coal identification, adding well trips to condition the hole and additional well costs for logging runs. In this paper, machine learning methods are applied to identify coals from drilling and logging-while-drilling (LWD) data to reduce overall well costs. Machine learning algorithms include logistic regression (LR), support vector machine (SVM), artificial neural network (ANN), random forest (RF), and extreme gradient boosting (XGBoost). The precision, recall, and F1 score are used as evaluation metrics. Because coal identification is an imbalanced data problem, the performance on the minority class (i.e., coals) is limited. To enhance the performance on coal prediction, two data manipulation techniques [naive random oversampling (NROS) technique and synthetic minority oversampling technique (SMOTE)] are separately coupled with machine learning algorithms.Case studies are performed with data from six wells in the Surat Basin, Australia. For the first set of experiments (single-well experiments), both the training data and test data are in the same well. The machine learning methods can identify coal pay zones for sections with poor or missing logs. It is found that rate of penetration (ROP) is the most important feature. The second set of experiments (multiple-well experiments) uses the training data from multiple nearby wells, which can predict coal pay zones in a new well. The most important feature is gamma ray. After placing slotted casings, all wells have coal identification rates greater than 90%, and three wells have coal identification rates greater than 99%. This indicates that machine learning methods (either XGBoost or ANN/RF with NROS/SMOTE) can be an effective way to identify coal pay zones and reduce coring or logging costs in CSG developments.
The Reduction of Pressure Gradients in Oil Pipelines by the Addition of Water: Numerical Analysis of Stratified Flow
Authors: Charles M.E. , Redberger P.J. 
Published: February 2020

This paper was presented at the AIChE - SPE Joint Symposium on Multiphase Flow in the Production and Drilling of Oil Wells, September 25–28, 1960, in Tulsa, Oklahoma

Abstract
The addition of water to crude oil pipelines appears to be an important method for decreasing the pressure gradient for a given oil throughput. Although the concentric oil-in-water flow pattern provides the greatest possible reduction, the general case, in which the liquids are stratified as a result of the oil and water having different densities, is also characterized by reductions in pressure gradient.
To evaluate the magnitude of the pressure gradient reduction to be expected in stratified flow systems, the Navier-Stokes equations were solved by a numerical procedure utilizing a digital computer, for the laminar stratified flow of two Newtonian liquids - oil and water - in a circular pipe. Liquid flow rates were obtained for the flow of five hypothetical oils ranging in viscosity from 4 to 1500 centipoises in the presence of water, by computing the oil and water velocity profiles for a series of arbitrary oil-water interface positions. It was found that the maximum values for the pressure gradient reduction factor ranged from 1.12 to 1.31 for the five oils and occurred at water contents ranging from 12 to 93 per cent respectively.
The computed reduction factors were considerably lower than experimental values and this appears to indicate that wave motion and mixing at the oil-water interface produces a further and very significant reduction in the pressure gradient.
Cement Plug for Water Shut-Off Using Coiled Tubing Hydrostatic Valve: Case Studies
Authors: Mehmood Azfar , Sattar Abdul , Akbar Nabeel , Temuri Saqib Jah , Fazal Adnan , Saeed Salman , Khokhar Saad Yousuf , Yousuf Arif , Rehman Aziz ur , Dar Afnan Ahmed 
Published: February 2020

Abstract
Accurate fluid placement had always been a challenge in depleted reservoirs. Criticality of such jobs multiplies when cement plug is to be placed in a depleted reservoir or when there is a marginal tolerance in terms of volume or differential pressures for the placement of cement plug. Various techniques are used in industry to spot specific cement slurry volume in stages to get accuracy in plug depth. Bailers being most successful, demerits from having very less volume of cement slurry which can be placed, resulting in multiple runs. To effectively place fix quantity of chemical plug or cement slurry in a well, a coiled tubing conveyed hydrostatic valve (fluid retainer) can be successfully deployed, by placing known quantity of liquid only.
In depleted oil and gas wells (especially the ones in secondary recovery phase) there is a static sump present. Reservoir shut off solutions cannot be used in this scenario as the increase in hydrostatic head causes loss of the pill into the the reservoir zone. In such scenarios, cement plugs are preferred to be dumped using dump bailer, however, for volumes larger than 1 bbl bailer option is not feasible. Hydraulics balance is crucial to job success, and such applications virtues the use of a coiled tubing conveyed Hydrostatic Valve.
This paper discusses operation of hydrostatic valve and present case studies of two wells in Pakistan, where this technology is effectually implemented together with acid soluble and salt saturated cement slurry.