bluuebunny/crossref_metadata_2025_split huggingface dataset:
Mobility Control With Polymer Solutions
Authors: Gogarty W.B. 
Published: June 2014

Abstract
With the use of polymer solutions in secondary recovery operations, the need has developed to understand the mobility control mechanism. This study investigated mobility control by considering both permeability and rheological effects. Experiments used a high molecular weight, partially hydrolyzed polyacrylamide polymer. Flow studies took place in reservoir and Berea cores having zero oil saturation. Effective size of the polymer flow unit was inferred from Nuclepore filter tests. Clay studies indicated the particle size capable of decreasing the core permeability. Flushed permeabilities measured the approximate core permeabilities with flowing polymer solutions. These permeabilities were considerably lower than original values. With mobility data and the flushed permeability, maximum effective viscosities were determined for polymer solution flow in a core. Effective viscosities showed that rheological properties play an important part in mobility control with polymer solutions.
The study showed that permeabilities decrease and stabilize with polymer flow. At the lower permeabilities, high shear rates exist in the cores. Because of the pseudoplastic character of the polymer solution, the high shear rates caused low effective viscosities. This condition pointed to the inefficient use of the potentially high viscosity of the polymer solution at low shear rates.

Introduction
In the oil industry, a great deal of interest is being shown in the use of polymer solutions for secondary recovery and a number of polymer floods are being performed in the United States. Some of these floods have become commercial while others have been reported as failures. A number of floods are still in progress and remain to be evaluated. With the advent of polymer flooding, the need developed to understand the mobility control mechanism in porous media.
Metocean and Oil Spill Modeling
Authors: Michel C. , Quiniou V. , Vigan X. 
Published: June 2014

Abstract
This paper sets out to explain the global methodology developed by Total to improve the reliability of oil spill drift modeling by developing metocean skills in-house.
The role of oil spill modeling is not at present considered essential during an oil spill, despite the fact that its advantages have been clearly identified. Actually, model predictions should make it possible to –Forecast the drift of an oil slick–Identify the areas where the intervention teams should take action–Predict the period and areas that could be impacted–Inform neighboring installations, authorities and NGOs.
Oil & Gas Companies initially showed great interest in this new tool but, due to a series of poor modeling results, its place in the oil spill response was redefined. After several studies, these controversial results appear to originate in the questionable reliability of the current and wind data. To remedy this, Total created a "metocean & oil spill modeling" system to improve the quality of this data, which in turn will bring an improvement to oil-spill drift modeling results.
This paper explains the main steps of this system and details its advantages.
Its overall functioning has been tested in Total on a recent event: a gas and condensate leak on the Elgin platform in the North Sea. The main actions and conclusions are developed in this paper.
A retrospective analysis of the results on the Elgin event shows the system is effective, since the reliability of the predictions is estimated to be about 92% for the first day's forecast and about 77% for 2 days. So now, thanks to the improvements in metocean information, oil spill models can be considered as reliable tools for use in oil spill response.
Hydraulic Fracture - Field Test to Determine Areal Extent and Orientation
Authors: Reynolds J.J. , Scott J.B. , Popham J.L. , Coffer H.F. 
Published: June 2014

Abstract
This paper concerns field experiments to define the areal extent, orientation and thickness of an artificial fracture in the Sacatosa field, Maverick County, Tex. The fracture was made by a sand-oil treatment of 176,000 gal of lease crude containing a fluid-loss additive and 270,000 lb of 20–40 mesh subangular Poteet sand. The well was perforated with a jet gun, consisting of six shots in a single plane. Fourteen test holes were drilled at various locations around the fractured well. Drill-stem tests, Micro and Sonic Logs, coring and sampling of formation cuttings were used to determine the presence of the fracture in these holes. The test holes were drilled at distances up to 250 ft in a radial pattern around the fractured well. In addition to fracture areal extent and orientation, sand grain size before and after fracturing, erosion of perforations and fracture thickness were studied.

Introduction
The orientation, areal extent and thickness of artificially induced fractures in reservoir rock by hydraulic means have been discussed in great detail in the oil industry in recent years. Methods for initiating vertical and horizontal fractures have been tested in the laboratory and the field. Although the methods used give successful well stimulation, good field data on the physical characteristics of the fracture are lacking in the literature. It is recognized generally that properties of a fracture, such as thickness, sand placement in the fracture and shape, may vary from reservoir to reservoir. This paper gives data on size, orientation and sand placement in a large fracture initiated in a single plane in Sacatosa field, Maverick County, Tex. It is not intended as a speculative study; rather, it is restricted to actual field data on fracture properties. No attempt is made to prove that the same type of fracture occurs in all wells.
Identification, Classification and Prediction of Reservoir Nonuniformities Affecting Production Operations
Authors: Hutchinson C.A. , Dodge C.F. , Polasek T.L. 
Published: June 2014

Abstract
A study of sandstone outcrops typical of producing horizons has been undertaken to develop a method for predicting the size, shape and permeability contrast of reservoir nonuniformities. This paper is a progress report and presents the tentative conclusions reached from the study of several Cretaceous age outcrops in the Four Corners area and of the Woodbine outcrop around Dallas.
The results to date suggest that nonuniformities in sandstone reservoirs may be classified according todepositional environment androck texture and cement content.
Within a sandstone unit, there will be no drastic variations in permeability providing the cement content is not sufficient to control the permeability. For this noncement-controlled or texture-controlled permeability situation, up to a 5:1 ratio of maximum-to-minimum permeability is expected for measurements on 1 x 7/8-in. core plugs. When the permeability of the sand is cement-controlled, the maximum-to-minimum ratio of permeability values within a sand unit may exceed 100:1.
Clean shale sections tend to be continuous over great distances, whereas sandy shale sections will be fairly continuous only in ripple-marked and horizontally bedded layers of the formation. In cross-bedded sandstones, the sandy shale sections will tend to be discontinuous.
The conclusions reached in this study so far suggest that, if the bedding, textural qualities and cement content are known in blanket sandstones, the sizes, shapes and permeability contrast of nonuniformities within the sandstone are predictable. The bedding, textural properties and cement content can be determined from well cores.

Introduction
This is a progress report on a major research study that is far from completion. The report is presented with the hope that the limited accomplishments to date may impart worthwhile insight to some and that others of the industry will become sufficiently interested in this frontier of technology to lend their efforts to developing an understanding of reservoir nonuniformities and the engineering procedures for including their effects in reservoir performance.
Industrial Cogeneration Appliance--An Example of a Drilling Rig
Authors: Radišic Ognjen , Radišic Mladen , Maksimovic Rado , Radakovic Nikola 
Published: June 2014

Summary
Focusing on one branch of heavy industry (deep oil and gas drilling) in our work, we come to the importance of energy efficiency, or rather to the problem of energy-efficiency increase. In this paper, some major issues in the field have been highlighted, including the energy potentials in drilling rigs and a proposal on how to increase energy efficiency by applying cogeneration to diesel engines within the scope of the contribution to rational use of energy potentials.
Field-Scale Simulation of Cyclic Solvent Injection (CSI)
Authors: Chang Jeannine , Ivory John 
Published: June 2014

Summary
Only 5-10% of the oil in Lloydminster heavy-oil reservoirs is recovered during cold heavy-oil production with sand (CHOPS). CSI is currently the most active post-CHOPS process. In CSI, a solvent mixture (e.g., methane/propane) is injected and allowed to soak into the reservoir before production begins (Fig. 1). CSI has been focused on heavy-oil recovery from post-CHOPS reservoirs that are too thin for an economic steam-based process. It has been piloted by Nexen and Husky and was a fundamental part of the CDN40 million joint implementation of vapour extraction (JIVE) solvent pilot program that ran from 2006 through 2010. This paper describes field-scale simulations of CSI performed with a comprehensive numerical model that uses "mass-transfer" rate equations to represent nonequilibrium solvent-solubility behaviour (i.e., there is a delay before the solvent reaches its equilibrium solubility in oil). The model contains mechanisms to consider foaming or to ignore it, depending on the field behaviour. It has been used to match laboratory experiments, design CSI operating strategies, and to interpret CSI field pilot results. The paper summarizes the impact on simulation predictions of post-CHOPS reservoir characterizations where the wormhole region was represented by one of the following five configurations: (1) an effective high-permeability zone, (2) a dual-permeability zone, (3) a dilated zone around the well, (4) wormholes (20-cm-diameter spokes) extending from the well without branching, and (5) wormholes extending from the well with branching from the main wormholes. The different post-CHOPS configurations lead to dramatically different reservoir access for solvent and to different predictions of CSI performance. The impacts of grid size, upscaling, solvent dissolution and exsolution rate constants, and injection strategy were examined. The assumption of instant equilibrium solubility resulted in a 23% reduction in oil production compared with when a delay in solvent dissolution and exsolution was allowed for. Increasing the gridblock size by a factor of nine reduced the predicted oil production five-fold. Assuming isothermal behaviour in the simulations decreased predicted oil production by 17%.
How To Assess a Depth of Permeability Impairment of the Wellbore Zone Using Drillstem-Testing Flow-Period Data
Authors: Szpunar Tadeusz , Budak Pawel 
Published: June 2014

Summary
This paper provides a simple procedure for evaluation of depth of permeability impairment within the wellbore zone using drillstem-testing (DST) flow-period data. Also computed are skin factor, permeability of the wellbore zone, and permeability of the reservoir. Contrary to the type-curve-fitting method, straight-line approximations were used to compute these values. All calculations presented are for "real-world" data.
Subcool, Fluid Productivity, and Liquid Level Above a SAGD Producer
Authors: Yuan Jian-Yang , Nugent Daniel 
Published: June 2014

Summary
Thermodynamic steam-trap control, or subcool control, in a typicalsteam-assisted gravity-drainage (SAGD) production is essential to the stabilityand longevity of the operation. It is achieved commonly through the control offluid production. The goal of such control is to maintain a steady and healthyliquid production without allowing steam from the injector to bypass to theproducer. Therefore, it is effectively a control of the liquid level above theproducer. Unfortunately, it is not practical to monitor this liquid level. Arule-of-thumb subcool-per-metre estimation of 10°C/m of liquid level is popularin the industry; however it does not prove to hold in many situations. Thispaper presents a study of the dynamics of SAGD-production control with aresulting algebraic equation that relates subcool, fluid productivity, andwellbore drawdown to the liquid level above a producer. The main conclusions ofthis study include
There is no minimum subcool value for a pure-gravity-drainage scenario;however, as the wellbore drawdown is considered, there is a minimum subcoolvalue in order to maintain the stability of fluid flow.
For a given productivity, the liquid level increases as subcool increasesor as wellbore drawdown decreases.
For each given set of operating parameters, there exists a criticalproductivity below which SAGD operation would halt.
Before the steam chamber reaches the top of the reservoir, the fluidproductivity is limited by the vertical distance between the injector and theproducer; the larger the distance, the higher the fluid production rate canbe.
A verification of this analysis was conducted by a series of numericalreservoir simulations. Although limited to two dimensions, we expect that thisanalysis captures the main physics amid the dynamic complexity ofSAGD-production control. The resulting algebraic equation can be used forbetter understanding of the dynamics of subcool control and for determiningoperation strategies.
Modelling of Bitumen-and-Solvent-Mixture Viscosity Data Using Thermodynamic Perturbation Theory
Authors: Zirrahi Mohsen , Hassanzadeh Hassan , Abedi Jalal 
Published: June 2014

Summary
Viscosity is an important transport property for engineering design and simulation of bitumen production and transportation. During the production of bitumen with solvent injection, steam-assisted gravity drainage, or expanding solvent steam-assisted gravity drainage, the oil/solvent mixture encounters various temperature and pressure conditions. Therefore, a model is necessary to predict the viscosity of the mixture of bitumen and solvent in wide ranges of temperatures, pressures, and compositions (T-P-x). In this work, we propose a semitheoretical viscosity model based on the Arrhenius mixing rule and considering the effect of association between the molecules of the solvent and the bitumen. To achieve this purpose, thermodynamic perturbation theory (TPT) is used to calculate the fraction of bonding solvent molecules. We calculate the viscosity of the solvent in wide temperature and pressure ranges using the modified Enskog theory (MET). Results show an acceptable agreement between the predictions of this model and experimental viscosity data of bitumen saturated with different solvents (CH4, N2, CO2, and C2H6) at various T-P-x ranges. These experimental data cover the typical T-P-x ranges of oil-recovery methods.
Geologic Heterogeneity and Economic Uncertainty of Subsurface Carbon Dioxide Storage
Authors: Heath J.E. E , Kobos P.H. H , Roach J.D. D , Dewers T.A. A , McKenna S.A. A 
Published: June 2014

SummarySubsurface storage of carbon dioxide (CO2) has geologic and economic uncertainties that must be addressed as part of a performance assessment. A model presented herein links uncertainty in geologic heterogeneity and associated well injectivity to variability in costs. This includes a novel averaging scheme for CO2 injectivity using geostatistical realizations of petrophysical properties and a systems-level model that includes costs of drilling and completion of injection wells. Using the Mount Simon Formation in the Illinois basin, USA, as a test case, this analysis demonstrates how the underlying costs of CO2-subsurface-storage projects can be highly sensitive to geologic heterogeneity.
Field Results for Recovering Oil From a Steam-Project Pressure-Isolation Wall
Authors: Miller Karl A. , Xiao Yi 
Published: June 2014

Summary
The Lloydminster, Saskatchewan, area Pikes Peak steam project has been onproduction since 1982. A key part of the development strategy was use of anundeveloped pressure-isolation wall to allow the two halves of the pool to bedeveloped with different time schedules and exploitation processes. Use of thepressure-isolation wall allowed different exploitation options to be used, butduring late project life the oil left in the wall needed to be recovered toenhance project economics. A significant challenge in recovering the oil in thewall was the lack of pressure containment or oil saturation on both flanks,resulting in the need for a gentle recovery process to avoid pushing the oiloutside the wall. On the basis of numerical-simulation results, the recoveryprocess selected for the wall was use of two cyclic-steam-stimulation (CSS)horizontal wells operated in a gentle manner. After the horizontal wells weredrilled, however, temperature logs showed the reservoir surrounding one of thehorizontal wells had already been heated by offsetting steam injection, andthat well has been continually produced at good rates without the need forsteam stimulation. The second new horizontal wall well was initially operatedsuccessfully using the CSS process designed using numerical simulation, butthat well is now also being operated in an external drive mode. The results ofthis field study show that the oil in a wall used to pressure isolate sectionsof a steam-project pool can be recovered economically without pushing the oilinto the adjacent depleted areas by use of processes designed to account forlocal wall conditions.
Dead Horizontal Well Revival Utilizing Fiber-Optic Enabled Coiled Tubing Combined with Underbalance Perforating Gun Deployment Technique (Case Study)
Authors: Subaie Fehead , Otaibi Nashi , Sultan Fouad , Burov Anton , Keong Azwan 
Published: June 2014

Abstract
In many oil fields water production often threatens the reservoir performance and economic viability of wells. Excess unwanted water production can cause an increase in production costs and a decrease in productivity. To mitigate this, it is crucial to utilize water management techniques to reduce water cut (WC), optimize oil production, extend the well life and recover idle wells.
The most effective technique for water shut off (WSO) treatments in Saudi Arabia comparatively to the costly workover rig treatments was proved to be a rigless WSO using mechanical isolation especially when it gives options to perform additional operations with the single rigup.
This paper describes the first time — in Saudi Arabia — implementation of the mechanical rigless WSO method, used to mechanically isolate a watered open hole section. This isolation is accomplished by utilizing fiber optic enabled coiled tubing (FOECT) telemetry and then setting an inflatable packer in the liner. It is capped with cement following perforation treatment, by using a completion insertion and retrieval under pressure (CIRP) deployment system, which allowed the guns to be run and pulled under live well conditions without killing the well.
The depth correlation for the packer setting — and later for perforation depth correlation — was performed by fiber optic bottom-hole assembly (FOBHA-GR). The inflation of the packer and the injection through it were monitored and adjusted realtime with the FOBHA-Pressure - Temperature - Casing Collar Locator (FOBHA-PTC) measurement inside and outside the FOCT string. FOBHA utilize deployment method from CIRP technology to perforate the new formation by using the TCP E-Fire firing head under well dynamic underbalanced conditions.
Recent production results showed a previously dead well flowed at 10 thousand barrels per day oil rate with 12% water cut.
This innovative combination of WSO solution with FOECT and CIRP techniques proved to be an effective method to minimize operational time, equipment and footprint on location, and efficient perforating in a single underbalance run at one rigup.
This paper also discusses the challenges faced during job execution, lessons learned, and experience gained to optimize similar jobs in the future.
A New Model for the Accurate Prediction of Liquid Loading in Low-Pressure Gas Wells
Authors: Luan Guohua , He Shunli 
Published: June 2014

Summary
The critical gas velocity and flow rate for unloading liquids from a gas well has been the subject of much interest, especially in old gas-producing fields with declining reservoir pressures. For low-pressure gas wells, Turner's model (also called Coleman's model) is judged as more suitable for predicting liquid loading in gas wells. However, field practice proves that there are still a number of low-pressure gas wells producing without loadup when the production rate is lower than Turner's minimum production rate.
On the basis of experimental results, a new approach for calculating the critical gas-flow rate is introduced in this paper, which adopts Li's basic concepts, while taking into account the impact of the changes of gas-lifting efficiency caused by the rollover of droplets in the process of rising. A dimensionless parameter, loss factor S, is introduced in the new model to characterize the extent of the loss of gas energy.
Well data from Coleman's paper (Coleman et al. 1991) were used in this paper for validation of the new model. The predicted results from the new model are better than those from Li's model, and even better than Turner's model. The new model is simple and can be evaluated at the wellhead when the pressure is less than 500 psia and the liquid/gas ratios range from 1 to 130 bbl/MMscf, which is suggested by Turner et al. (1969) to ensure a mist flow in gas wells.