bluuebunny/crossref_metadata_2025_split huggingface dataset:
Numerical Simulation of Fully Coupled Fluid-Flow/Geomechanical Deformation in Hydraulically Fractured Reservoirs
Authors: Garcia J. G. , Teufel L. W. 
Published: December 2007

Abstract
A fully-coupled geomechanics/fluid-flow simulation model has been developed to study the behavior of the pore pressure and stress distribution in a hydraulically fractured well-reservoir system. The 3D finite difference, fully implicit model takes into account the non-linear poroelastic deformation of the reservoir rock. The numerical model incorporates a local grid refinement around the perforation depth. Equations that govern fluid flow are coupled with the equations that govern rock deformation in the fracture and the reservoir, then the resulting equations are solved numerically under different reservoir-fracture conditions. The initial and boundary conditions used in the solution of the equations are defined as follows: (i) Zero incremental pressure and displacements at initial conditions and (ii) Closed system for the fluid flow model, non-deformable boundaries. A laboratory-derived stress-dependent permeability correlation is introduced to compute the permeability in both the rock without fracture and the fractured rock. The use of this correlation avoids the need to have initial permeability values and these values are computed using the effective stress acting on the rock. Simulator is applied to selected simulation examples to show the effects of isotropic and anisotropic stress states on the fracture shape and distributions of fluid pressure and vertical and horizontal stresses.
Oil Recovery by Near-Miscible SWAG Injection
Authors: Sohrabi M. , Danesh A. , Tehrani D. H. 
Published: December 2007

AbstractWe present micromodel visualization of pore-scale displacement mechanisms and fluids distribution during recovery of residual oil by near-miscible Simultaneous-Water- And-Gas (SWAG) injection under conditions of very low gas-oil interfacial tension (IFT) and negligible gravity forces. A 3- phase fluid system with gas-oil IFT of 0.08 mN/m, representing a near-miscible fluid system, together with high-pressure (5100 psia) micromodel were used for the flow experiments.We demonstrate that in near-miscible SWAG injection, the oil recovery continues significantly and almost all of the oil that has been contacted by the gas will be recovered, after the main gas breakthrough. This oil is recovered by a microscopic mechanism, which is strongly linked to the low IFT between the oil and gas and to the perfect spreading of the oil over water, both of which occur as the critical point is approached. We have performed experiments with different SWAG (gas/water volumetric) ratios and we show that the ultimate oil recovery during SWAG injection is almost independent of SWAG ratio, within the tested range of 20 to 50%. This makes SWAG injection an attractive IOR process especially for reservoirs where continuous and high rate gas injection is not possible (e.g. due to supply constraint). In oil reservoirs that cannot export gas (remoteness from the market) WAG (for abundant gas volume) or SWAG (for low or high volume of gas) can be implemented.
A Systematic Approach to Predicting Liquid Loading in Gas Wells
Authors: Guo B. , Ghalambor A. , Xu C. 
Published: December 2007

Abstract
Loading up of liquids in wellbore has been recognized as one of the severe problems in gas production for many years. Accurate prediction of the problem is vitally important for taking timely measures to solve the problem. Although previous investigators have suggested several methods to predict the problem, results from these methods often show discrepancies. Also these methods are not easy to use due to the difficulties with prediction of bottom hole pressure in multiphase flow. An accurate and easy-to-use method is highly desirable. This paper fills the gap.
Starting from Turner's analysis for prediction of the minimum gas velocity for liquid removal, the minimum kinetic energy of gas that is required to lift liquid droplets was determined in this study. In order to compare gas kinetic energy with the minimum required kinetic energy, a 4-phase (gas, oil, water, and solid particles) flow model was developed for mist flow. Applying the minimum kinetic energy criterion to the 4-phase flow model resulted in a closed form analytical equation for predicting the minimum gas flow rate.
The kinetic energy theory indicates that the controlling conditions for liquid drop removal in gas wells are bottom hole conditions rather than top-hole conditions. Our case studies show that Turner's method with 20%-adjustment still under-estimates the minimum gas velocity for liquid removal, and the newly developed equation is more accurate than Turner's method. The new method is easier to use than other existing methods. This paper provides production engineers with a systematic approach to predicting the minimum gas production rate for the continuous removal of water and oil from gas wells. Engineering charts are provided for two typical tubing sizes and wellhead pressures.
Using Neural Networks to Estimate Monthly Production: A Case Study for the Devonian Carbonates, Southeast New Mexico
Authors: Schrader S. M. , Balch R. S. , Ruan T. 
Published: December 2007

Abstract
Neural networks are a well developed computational intelligence technology with many possible applications in the oil and gas industry. For this study a neural network was developed to predict production potential for a single formation, prior to drilling, over a 16,000 square mile area of SE New Mexico. The process involved gathering data for use as potential inputs, collecting production data at known wells, selecting optimal inputs, developing and testing various network architectures, making predictions, analyzing and applying the results.
Variables considered as potential inputs included the thickness of the primary source rock (Woodford shale), total organic carbon (TOC), production index (PI), paleo thickness, curvature of paleo structure, and permeability. Two variables were derived; the product of Woodford thickness, TOC and PI, termed generative potential, and the log of generative potential. Variables were interpolated using kriging over the study area.
The neural network was trained to identify the production at a set of wells with attempted production from the formation. Production was measured in barrels of oil equivalent per month (BOEPM) averaged over the first year 12 months of production. The data included producing wells and dry holes.
Potential input variables were tested against the output to determine the best variables for training. First, a fuzzy ranking algorithm selected Woodford thickness and TOC. A secondary correlation study also recommended Woodford thickness and TOC, and added permeability and generative potential.
A series of neural networks were developed to test different architectures. The architectures were compared based on the r2 correlation while considering the possibility of overtraining based on the size of the input variable set. Random subsets of data were excluded for blind testing. A 4-6-1 architecture with an r2 correlation of 0.84 was selected. The neural network was re-trained multiple times achieving consistent correlations in each test.
Once trained, the network was used to predict production over the entire region. This predicted production was further refined by excluding production at locations where the Woodford shale was not present. Results were evaluated by inspecting a map of predicted production and performing statistical testing, including a correlation of predicted and actual production, which produced a correlation coefficient of 0.79. The results were then used by the Devonian FEE Tool, an expert system designed to reduce exploration risk.
Increased Production Results from Pilot Horizontal Waterflood in Osage County, Oklahoma
Authors: Westermark R. V. , Schmeling J. , Dauben D. , Robinowitz S. , Weyland H. V. 
Published: December 2007

Abstract
This paper details the results of a three-year project to test horizontal waterflooding as a means of improving oil recovery from the Bartlesville sandstone in an abandoned 100-year-old oil field in Osage County, Oklahoma. Supported by a grant from the Department of Energy (DOE), this work was conducted by Grand Resources, Inc., an independent operator in Tulsa, Oklahoma. The project was initiated based on the concept of using three parallel horizontal wells (an injector straddled by two producers) in a heel-to-toe configuration. The pilot test evolved into an oil rim recovery project with pressure support coming from a vertical injection well, due to reservoir heterogeneities and lower-than-expected oil saturations.
Key technical aspects are discussed, including reservoir screening and the selection process; substantiating the primary and secondary production history; interpreting the depositional environment, including natural fracture orientation and a wellbore stability evaluation. Reservoir characterization is initially based on vertical logs and is modified when horizontal openhole logs become available. Characterization provides the details necessary for the reservoir simulation used to predict oil recovery and assess the economic viability. The simulation process is ongoing and updated as additional data is acquired.
Once waterflooding operations have begun, the technologies and methods employed to evaluate, manage and adjust both injection and production performance include: Evaluating production results.Conducting step rate and injection profile tests in the horizontal injection well.Running a full suite of open hole logs through the short radius curve, including an acoustic borehole televiewer, to determine fracture frequency and orientation.Adjusting injection water volume to assist in reducing operating expenses yet maintain adequate reservoir pressure support for high fluid withdrawal rates.Re-drilling the horizontal producing wells closer to the top of the reservoir to significantly increase the oil cut.
The short radius drilling system is explained, in addition to the drilling of the lateral wellbores.
Oil recovery from the originally designed pilot was disappointing due to the unexpectedly high water saturations that were encountered. However, results from the modified pilot are much more encouraging, with 15 to 20 BOPD being produced from a thin oil column overlaying water.
Developing the Obaiyed Tight Gas/Condensate Field, Egypt – A Case Study
Authors: Strating E. H. H. , Amin S. , Samiee R. A. , Shanab M. A. , Ebied M. , Samaie A. A. , Ali N. M. 
Published: December 2007

AbstractThe Obaiyed tight Gas-Condensate field was discovered in 1992 and following 4 appraisal wells and 3 additional exploration wells the first integrated field development plan was issued in 1996. This formed the basis for an agreement to deliver 300 MMscf/d. The field was brought on stream in 1999 reaching full capacity in 2001. However, reservoir pressures dropped much faster than expected (30% rather than expected 10% annual production decline). In addition condensate production only reached 60% of initial expectation levels.A complete subsurface review in 2000-1 showed 5 key areas of concern that requiring specific attention in the FDP update: [1] more severe reservoir compartmentalisation, [2] poorer reservoir quality in NW part of the field, [3] lower CGR's, [4] Temperature constraints on flow lines, [5] Multiple fluid contacts. Consequently expected production levels and recovery factors had to be adjusted downward. A root cause underlying most of these issues (points [1], [3], [4], and in part [5]) can be traced back to the design and duration of the early well tests.Three years after the integrated review the reservoir/well behavior is very much in line with the 2001 model, indicating the quality work done at the time.Based on the above solid models, the future development of the field has been optimized. It comprises the following key activities: Improved field & reservoir managementFull field booster-compressionProduction accelerationUnder Balanced DrillingThe aim of the paper is to present the Obaiyed Field Development case, lessons learnt, remedial action taken and future plans.
Pickling Well Tubulars Using Coiled Tubing: Mathematical Modeling and Field Application
Authors: Al-Mutairi S. H. , Hill A. D. , Nasr-El-Din H. A. 
Published: December 2007

Abstract
Coiled tubing is usually used to conduct acid pickle treatments. The purpose of the treatment is to prevent pumping damaging materials into the formation prior to the main acid job. In this case, the acid is pumped down the coiled tubing, and then flowed up through the tubing-coiled tubing annulus. Pickling is a process of flow with heterogeneous reactions occurring with mill scale (Fe3O4) and other contaminants at both the inner wall of the production tubing and the outer surface of the coiled tubing.
Pickling is an essential part of well stimulation treatments if the main treatment fluids (acidizing, fracturing, gravel packing, etc.) are to be bullheaded. However, it appears that traditional pickle practices are overestimating the required acid volume and/or concentration. Field data indicated that excessive acid volumes are used for tubing pickle because large returns of unreacted acid are usually recovered on the surface.
In this paper, mechanisms to explain the behavior of acid contact with the tubing are presented and a model for predicting acid consumption and dissolution of tubular contaminants is developed. The model includes reactions of acid with mill scale. A system of non-linear partial differential equations is developed and the equations are solved numerically to predict the concentrations of major species as a function of axial position along the tubing and in the effluent from the well during flowback.
Field application included pickling of low-carbon steel tubing (11,900 ft of 5.5-inch C-95) using coiled tubing. A slug of 5,000 gals of 20 wt% HCl with additives was used. Samples were collected from the treated well during the flowback of pickling treatment. The model was used to predict the concentrations of various species in the well flowback samples. Model predictions for acid, chloride ion, and total iron concentrations were in good agreement with field results. In addition, the model proved to be a valuable tool in optimizing future pickling treatments.
Smart Operations: Cheap? High-tech? Or Simply the Best Fit? Optimized Drilling Solutions on the South Pars Field, Offshore Iran
Authors: Johannessen B. , Vestvik J. 
Published: December 2007

Abstract
In this paper we will discuss the drilling optimizations implemented in the South Pars field, which has resulted in one year of saved rig time.
We will cover the improvements introduced to the drilling process and also the technologies and equipment utilized to achieve the success so far; such as optimized well trajectories for performance drilling, introduction of PDC bit technology in combination with ultra high powered steerable motors, cementing techniques and drilling fluid optimization.
Flow-Rate Optimization of Aerated Fluids for Underbalanced Coiled-Tubing Applications
Authors: Ozbayoglu M. E. , Omurlu C. 
Published: December 2007

Abstract
Coiled tubing (CT) is widely associated with underbalanced drilling technologies. Especially in depleted reservoirs, drilling need for underbalanced and extended reach wells is increased where CT is widely used. In this work, optimization of volumetric requirements for liquid and gas phases is investigated in long horizontal and inclined sections of CT applications for underbalanced drilling. A mathematical model is introduced in order to predict the flow characteristics of multiphase flow through an annulus. Flow patterns and frictional pressure losses are evaluated using the experimental data of a wide range of liquid and gas flow rates recorded at a field-scale annular flow loop with common CT drilling dimensions as well as circular pipes. Practical curves are developed for determining the optimum flow rate combinations for CT applications using the developed model. A sensitivity analysis is also conducted on underbalanced and CT drilling parameters on pressure drop and flow patterns.
Multiple Model Seismic and Production History Matching: A Case Study
Authors: Stephen K. D. , Soldo J. , MacBeth C. , Christie M. 
Published: December 2007

Abstract
Time-lapse (or 4D) seismic is increasingly being used as a qualitative description of reservoir behaviour for management and decision making purposes. When combined quantitatively with geological and flow modelling, as part of history matching, improved predictions of reservoir production can be obtained. Here, we apply a method of multiple model history matching based on simultaneous comparison of spatial data offered by seismic, as well as individual well production data.
Using a petro-elastic transform and suitable re-scaling, forward modelled simulations are converted into predictions of seismic impedance attributes and compared to observed data by calculation of a misfit. With a similar approach applied to dynamic well data, the total misfit is used to update model probabilities in a Bayesian framework. These are then used to guide the re-sampling of the parameter space, generating multiple models using the quasi-global stochastic Neighbourhood Algorithm (NA) method. This approach improves on gradient-based methods by avoiding entrapment in local minima and can be used to efficiently analyse uncertainty of the matched parameters.
We demonstrate the method by applying it to a UKCS turbidite reservoir, updating the operator's initial model, which had previously been history matched to dynamic well data by conventional methods. We consider a number of parameters to be uncertain. The reservoir's net to gross is initially updated to better match the RMS amplitudes of the observed seismic baseline survey. We match simultaneously for permeability, fault transmissibility multipliers and the petro-elastic transform parameters. Our results show a good match to the observed seismic and dynamic well data with significant improvement to the operator's base case.
Potential Non-Traditional Uses of By-Product E&P Produced Sulfur in Kazakhstan
Authors: Beall P. W. , Neff J. M. 
Published: December 2007

Abstract
Kazakhstan based oil & gas companies recover approximately 2,000 to 3,000 metric tons per day of elemental sulfur from their product streams (approximately 500 tons of elemental sulfur is recovered for every 100,000 barrels of extracted petroleum in Kazakhstan). The bulk of the sulfur is recovered by Tengizchevroil (TCO). In Europe and the United States recovered elemental sulfur is normally sold into the chemical and manufacturing market as a raw material for:phosphate fertilizer (50%)sulfuric acid, detergents, and other chemicalsmetal and fiber industriespaint manufacturerubber productspaperpharmaceuticals
By-product elemental sulfur can potentially be used as a binder replacement in petroleum asphalt and Portland concrete as sulfur modified asphalt and concrete to meet or exceed American Society for Testing and Materials (ASTM) and/or American Concrete Institute (ACI) standards.

Potential Applications for Sulfur Polymer Concrete & Sulfur Extended Asphalt
Improving the highway infrastructure using sulfur modified concrete and asphalt might be a steady outlet for locally produced elemental sulfur. The sulfur extended asphalt can extend current Kazakhstan asphalt production capabilities by upwards of fifty weight percent (25 volume percent).
Other potential outlets for Kazakhstan produced sulfur include:Sulfur polymer concrete slabs and blocks for constructionSulfur Polymer Stabilization Solidification for radioactive and mercury contaminated materials

Screening-level Ecological Assessment for Sulfur Modified Concrete and Asphalt
The environmental behavior of these sulfur-modified construction materials resembles that of conventional Portland cement concrete and hot mix paving asphalt, except for the possible release of sulfur to the environment.
Tertiary Oil Recovery With Microbial Biosurfactant Treatment of Low-Permeability Berea Sandstone Cores
Authors: Maudgalya S. , McInerney M. J. , Knapp R. M. , Nagle D. P. , Folmsbee M. J. 
Published: December 2007

Abstract
Experiments focused on tertiary oil recovery of waterflood residual oil using a bio-surfactant flooding process are reported in this paper. Significant quantities of water flood residual oil were recovered when very low concentration bio-surfactant solutions were flooded through 25-200 md Berea sandstone cores. The residual oil recovery ranged between 35% and 45% as surfactant concentrations varied from 35-41 ppm.
Cleaned and dried Berea sandstone cores, six inches long and one and half inches in diameter with an average porosity of 16.0 % were first saturated with 5.0% NaCl brine, then saturated with 340 API crude oil and finally waterflooded to near residual oil saturation. Thirty five to forty five percent of that residual oil was recovered when the cores were flooded with surfactant combined with a 0.001% by vol. co-surfactant alcohol and 1000 ppm of partially hydrolyzed polyacyalamide (PHPA) as mobility control polymer. The co-surfactant alcohol was added to reduce the effect of salinity.
The bio-surfactant concentrations reported are much lower than those previously reported in synthetic surfactant laboratory tests. The oil recovery in terms of bio-surfactant consumed is also substantially higher than previous surfactant tests. This tertiary recovery process may help improve oil recoveries from many marginal oil fields operating a waterflood that produce small amounts of oil at high water cuts or those that have been abandoned due to uneconomic operating costs but still contain significant amounts of oil.
Evaporative Clean-Up of Water-Blocks in Gas Wells
Authors: Mahadevan J. , Sharma M. M. , Yortsos Y. C. 
Published: December 2007

Abstract
The flow of a gas in to a wellbore in a production well can result in the evaporative cleanup of water blocks. This occurs primarily due to the expansion of gas resulting in additional water being evaporated in the near wellbore region. This study presents for the first time, equations and a model to calculate the rate at which the water block is removed in both fractured and unfractured gas wells.
It is shown that the removal of water by the expanding gas leaves behind a saturation profile that is qualitatively different for low and high permeability rocks. As a consequence the increase in gas relative permeability or the well productivity with time can vary substantially depending on the rock permeability and the well drawdown. The model allows us to compute the impact of evaporative cleaning on well productivity.
It is seen that high permeability rocks clean up significantly faster. It is also observed that unfractured wells may require a very long time to cleanup. Large pressure drawdowns as well as the use of more volatile fluids such as alcohols result in significantly faster cleanup. A distinctive feature of the study is that the model equations are formulated and solved completely without the assumption of skin factors for the damage zone. Thus the prediction of cleanup rates can be made more accurately.
Multilateral Horizontal Well Productivity
Authors: Yildiz T. 
Published: December 2007

AbstractThis paper presents experimental and theoretical investigations of multilateral/duallateral horizontal well performance in areally anisotropic reservoirs. The investigation is based on a 3D analytical solution. The analytical solution considers an arbitrary orientation of the multilaterals/duallaterals in horizontal plane.Experimental study was conducted on an electrical analog apparatus. Experimental data was compared with the results from the analytical productivity model. Excellent agreement was obtained between the results.The multilateral well model was also compared against a model presented in the literature and verified.