bluuebunny/crossref_metadata_2025_split huggingface dataset:
Use of Mixed Surfactants to Improve Mobility Control in CO2 Flooding
Authors: Tsau Jun-Slung , Yaghoobi Hossein , Grigg Reid B. 
Published: December 2007

Abstract
The potential for using mixed surfactants at low concentration to improve mobility control in CO flooding was evaluated in laboratory experiments. We examined various mixed surfactant systems, such as alpha olefin sulfonate and ethoxylated alcohol sulfate, through foam durability and flowing tests.
In foam durability tests, we used a high pressure device to assess the stability of CO-foam bubbles and other pertinent properties. In flowing tests, we used a composite core to measure the flowing properties of foam in two differing sections of permeability.
Our foam durability test results showed that some mixed surfactants exhibit either comparable or better foam stability than the foam generated using the individual surfactants. During the foam flowing tests, we observed substantial mobility reduction of CO with mixed surfactants at very low concentration. Depending on types of surfactant mixed, some mixed nonionic and anionic surfactants demonstrate a better mobility reduction than that produced by an anionic surfactant alone. Additionally, improved mobility dependence on rock permeability is observed for most of the mixed surfactants.
P. 355
Compositional Simulations of a CO2 Flood in Ford Geraldine Unit, Texas
Authors: Malik Mohammad A. 
Published: December 2007

Abstract
The Ford Geraldine Unit (FGU), in Reeves and Culberson Counties, West Texas, produces from the Ramsey Sandstone in the upper Bell Canyon Formation. After primary depletion, a major portion of the reservoir was waterflooded in stages from 1969 to 1980 and is currently under a maturing CO flood that was started in 1981. However, because of high initial water saturation of 47.7% and some aquifer encroachment, the structurally low areas in the northeastern part of the reservoir were producing at very high water cut when the primary recovery approached its economic limit in 1968. As a result, this area responded very poorly to waterflood and no significant production has since been realized from this part of the unit. An estimated 10.1 MMSTB of the 12.9 MMSTB original oil in place (OOIP) remains in the reservoir in this area.
This paper presents results of a study in which advanced geologic, geophysical, and engineering reservoir characterization techniques have been applied to this part of the reservoir as a demonstration area for enhanced recovery. A conditionally simulated Stochastic-permeability-distribution model has also been developed. Compositional simulations were performed for CO flood using stochastic and layered permeability distributions and conservative estimates of fluid saturations.
Results indicate that a minimum of 10% of remaining oil in place (ROIP) can be recovered at breakthrough. Despite very high postwaterflood water saturations, the producing water cut gradually declines because of increase in hydrocarbon mobility as the injected CO dissolves in the oil. An important observation is that compositional simulations indicate significant incremental recovery after breakthrough. At the permissible gas-oil ratio (GOR) of 30 MSCF/STB, recovery of over 30% of ROIP is achievable from the demonstration area.
P. 375
Modeling Nonlinear Phenomena
Authors: Kapur Loveena , Lake Larry W. , Sepehrnoori Kamy 
Published: December 2007

Abstract
This paper discusses various ways to quantify nonlinear relationships, in general, and an application of the procedures explored to the Atlas of Major Texas Oil Reservoirs database compiled by The University of Texas Bureau of Economic Geology.
A system is nonlinear if the relationship between its input and output cannot be described by a straight line. Detecting such a relationship is confounded when random noise is present in the system's output. Most relationships in petroleum engineering are nonlinear. The first part of this work describes a numerical experiment that uses a known but noisy nonlinear function to generate system input. The function contains a parameter that specifies the degree of nonlinearity and an independent white noise component. For varying degrees of nonlinearity and noise we investigate which of three techniques, conventional linear regression, the optimal transform method, and a neural network, best reproduce the input-output response. As expected, linear regression works best (in the sense that it reproduces the known function) when nonlinearity is small. Optimal transforms work best for moderate amounts of noise and for nonlinear functions. No technique works, regardless of how nonlinear it is, when the system is dominated by noise.
The optimal transform procedure is illustrated by correlating oil recovery efficiencies reported in the Atlas of Major Texas Oil Reservoirs database. The results are obtained by performing the procedure on data sets that have been preprocessed by dividing according to drive mechanisms and/or reservoir classes.
P. 457
Polyethylene Lined Tubing in Rod Pumped Wells
Authors: Sirgo Eric C. , Gibson Edward D. , Jackson William E. 
Published: December 2007

Abstract
Although High Density Polyethylene (HDPE) lined tubing has been used regularly as a corrosion barrier to protect tubing in water injection applications, it has had limited application as a corrosion/wear barrier in rod pumped wells. With a goal of reducing well failures due to rod/tubing wear and internal tubing corrosion, polyethylene lined (poly-lined) tubing was installed in 17 rod pumped wells in the McElroy Field in Crane, Texas. It was assumed that the liners would provide sufficient reductions in friction between the rods and tubing to reduce wear, and that the sealed system would further reduce failures due to corrosion on the tubing strings. The pilot test shows that the wells equipped with the polyethylene liners have outperformed their previous failure histories. Overall the average runtime without an internal wear/corrosion related failure to the tubing and without a wear related failure to the rods has increased approximately 400% among the subject wells. Runtime including all failures has increased over 300%. In addition the system has demonstrated that used tubing can effectively be used in a field where traditionally new tubing had been purchased to extend run times. In those cases where artificial lift designs were not changed after the poly-lined tubing was installed, there was a measurable reduction in the Polished Rod Load Range, Balanced Torque and minimum stresses in the bottom of the rod string. Overall average failure ratio for the pilot wells has declined dramatically from 4.3 to.59.
P. 535
Fixed-Base Platform Concepts in Deep Water for the Gulf of Mexico
Authors: Campo J.J. , Serpas R.J. 
Published: December 2007

Abstract
This paper presents structural concepts utilized and proposed for deep water applications (400 ft. to 1000 ft.) in the Northern Gulf of Mexico.
Concepts presented include tripods, lifted and launched jackets and main and skirt piled platforms.
General analysis procedures for in-place platform design including dynamics and spectral fatigue are covered. Regulatory requirements and their effect on design and operation requirements are also discussed.
P. 185
A Study of Slug Characteristics for Two-Phase Horizontal Flow
Authors: Marcano R. , Chen X. T. , Sarica C. , Brill J. P. 
Published: December 2007

Abstract
Understanding the behavior of multiphase flow in pipelines is an important factor in the safe and economical design and operation of multiphase systems. Slug flow is a common and very complex occurrence in these pipelines.
Sixty-two slug-flow tests were conducted over varying combinations of gas and liquid flow rates. A total of 25,975 slugs were generated, ranging from 23 to 1145 slugs per test. The flow loop consisted of a 3.068-in diameter, 1378-ft long horizontal flowline, a two-stage air compressor, a centrifugal pump, and a data acquisition system utilizing LabVIEW™ with a Macintosh II ci computer.
The primary data collected during the experimental tests consisted of continuous readings of pressures, temperatures, flow rates, and liquid holdup. Processing of this data yielded slug translational velocities, slug lengths, pressure drops, slug length distribution, and slug frequency. Analysis of the results showed that the slug length distribution followed a Lognormal pattern. New correlations were developed for slug liquid holdup, film liquid holdup, slug translational velocity, slug frequency, average slug length and design slug length.
Using the data from this study, the new correlation for slug liquid holdup was compared with predictions from the correlations of Gregory et al.1 and Yang2. Similarly, the new correlation for slug frequency was compared with the correlation of Hill and Wood.
Flow-Induced Stress Distribution in a Multi-Rate and Multi-Well Reservoir
Authors: Sharma Amit , Chen Her-Yuan , Teufel Lawrence W. 
Published: December 2007

Abstract
The purpose of this study is to provide a model to infer the flow-induced rock-stress responses from the fluid-pressure transients of a vertical well in a homogeneous, anisotropic reservoir. The model is developed within the framework of Biot's theory of poroelasticity. Solutions for fluid-pressure and rock-stress responses are presented for an infinite reservoir in a state of plane strain. A published field case is presented to show the practical applications.
P. 97
Reservoir Description Techniques Improves Completion Economics in Piceance Basin Mesaverde Project
Authors: Schubarth S.K. , Mullen M.J. , Seal C.A. , Woodall R.S. 
Published: December 2007

Abstract
The Mesaverde formation in the Piceance Basin of western Colorado is a series of tight gas sands contained in a complex geological environment. Pay selection and completion techniques have varied greatly during the development of this formation. Production response varies greatly from well to well, and decisions on where and how to optimize completion economics are difficult. Consistent treatment sizes and designs are usually used even though some treatments may be over- designed while others are under-designed. Knowing where to spend Completion dollars and where to save them can substantially impact the economics of a development project in this Basin.
This paper will present a reservoir description technique that uses standard openhole well logs and helps operators to predict reservoir quality for individual sands. This prediction allows the operator to optimize the completion design and therefore maximize his economics. This technique has been applied to many wells, and the accuracy is documented through production analysis. Both total well production and individual sand production, determined with production logs, have been predicted through the use of this technique. This paper also examines the economic benefit of using this analysis technique will be presented. The authors believe that the methodology used can be applied to similar reservoirs to achieve similar results.
P. 129
Optimization of Fracture Cleanup Using Flowback Analysis
Authors: Willberg D. M. , Steinsberger N. , Hoover R. , Card R. J. , Queen J. 
Published: December 2007

Abstract
A field study in north-central Texas shows how flowback procedures can be optimized to improve fracture cleanup and well productivity in low-permeability formations. Load water and polymer returns from 15 Barnett shale hydraulic fractures were analyzed and quantified. These were massive hydraulic fracturing treatments (1.4 million lbm of sand and 10,000 to 15,000 bbl of fluid) in an ultra-low-permeability (0.001 md) formation. These wells were fractured using low gel loading borate-crosslinked fluid. Well productivity is correlated with fracture cleanup.
Aggressive flowback procedures improved fracture cleanup and well productivity. The maximum flowback rate was increased from 0.6 bbl/min at the beginning of the field test, to as high as 6 bbl/min. Polymer returns at conservative flowback rates, &lt; 3 bbl/min, averaged 31 ± 6% of the total amount pumped on the job. Polymer returns from wells aggressively flowed back, &gt;3 bbl/min, averaged 46 ± 9%. Aggressively flowed back wells produced on average 19% more gas over the first 180 days of production than conservatively flowed back offsets.
Recovery of polymer continued throughout the early stages of production in addition to the polymer returned during flowback. Significant polymer concentrations were recorded in produced water samples collected up to five months following the treatment. Recovery during production can yield 10 to 13 % of the polymer pumped during the job in addition to the amount recovered during flowback.
Similar patterns of polymer recovery are observed when the Barnett shale results are compared with those from the Codell formation (0.010 md) in Colorado. This is in spite of differences in treatment size, job design, and fluid selection. Therefore, it is plausible that the results from these two studies can be generalized, and applied to many other low-permeability formations. Significant differences are observed when the Barnett results are compared with those from the Cotton Valley formation in east Texas. These differences are primarily due to the production of water by the latter formation.
Case History: Formation Damage and completion Techniques in Water Sensitive Basal Colorado gas Reservoirs of Southeastern Albeta, Canada.
Authors: Claussner R.M. , Potocki D.J. , Stevens L.M. 
Published: December 2007

Abstract
Basal Colorado Channel sandstone reservoirs can be clay- bearing and highly water sensitive. This presents a technical challenge from reservoir performance and completion design standpoints. The sandstones are fine to medium grained mineralogically immature and chemically unstable litharenites with significant amounts of feldspar and volcanic rock fragments. Dissolution of these grains has contributed to the precipitation of variable but significant amounts of potentially damaging pore-filling kaolinite and pore-lining smectite, chlorite and chlorite/smectite clays. The combination of overall high clay and variable smectite content makes prediction of reservoir productivity from drill stem tests, conventional log response and routine core petrophysical measurements difficult. As these reservoirs contain gas-water contacts, hydraulic fracturing likely would result in high water production. Therefore, alternative completion and stimulation techniques were required.
This is a review of an integrated reservoir analysis approach which was successfully applied to several gas wells in these sandstones. This approach included: characterization of reservoir quality, laboratory core plug testing to define severity of formation damage, and application of test results to selection of completion fluids and completion/stimulation techniques. These included the use of an extended lance tool with a high salinity brine jetting fluid. Candidate selection criteria based on field experience are presented. Production results to date demonstrate that the procedures developed have resulted in successful completion and stimulation of these problematic clay-bearing gas reservoirs.
P. 209
Monte Carlo Techniques for Evaluating Producing Properties
Authors: Gilman J.R. , Brickey R.T. , Red M.M. 
Published: December 2007

Abstract
When purchasing property, selling property or estimating future cash flow from a project, forecasts of future production rates are required. Whether those forecasts are made with detailed reservoir simulation or decline curve techniques, there will be uncertainty in the forecasts. Even if the reservoir description was exact and an accurate reservoir simulation could be made, the field development plans would be uncertain because of uncertainty in future product prices and expenses. This paper demonstrates how Monte Carlo techniques were used to generate a range of production profile distributions to estimate the economic value of a producing property.
The basic methodology used decline curve equations for each well in the field to describe the future production rate of the wells. Hyperbolic decline equations were used for all wells. Gas-oil ratio was modeled by another empirical equation. The standard decline equations were modified to properly account for downtime while still honoring ultimate recovery. Downtime thus resulted in delayed production. However, a well did not always reach its expected ultimate recovery if it "failed" for mechanical reasons or if the field was abandoned for economic reasons. Well failure was modeled as a discrete distribution (i.e., the producing rate was multiplied by a value of zero or one).
Another unique aspect of the spreadsheet presented here was the incorporation of mechanical and workover failure probabilities. The decline equations were modified to allow for changes in reserves and rate as a result of workovers. The expected change in reserves could have some probability of being negative if there was risk of damaging a well as a result of an unsuccessful workover. Also, a workover could have some chance of failure resulting in no change to the expected reserves.
The parameters which were risked for each well were downtime, well life, well failure, workover reserves, workover incremental rate, workover failure, and workover expense. For the field, the "risked" variables were hydrocarbon prices and operating and abandonment expenses. All the uncertainty described here could not have been properly assessed without the use of Monte Carlo techniques.
P. 221
Production Analysis of Linear Flow Into Fractured Tight Gas Wells
Authors: Wattenbarger Robert A. , El-Banbi Ahmed H. , Villegas Mauricio E. , Maggard J. Bryan 
Published: December 2007

Abstract
Sometimes decline curves for tight gas wells indicate that linear flow may last for over 10 or 20 years. These decline curves may show outer boundary effects but no pseudo-radial flow. This paper presents decline curve analysis methods for such wells. Values for k xf and drainage area can be calculated. Stabilized (bounded) flow equations are also presented for forecasting. The solutions and type curves developed are for both infinite-acting and stabilized flow with either constant Pwf or constant rate. Several field cases are shown with example calculations.
P. 265
Multidisciplinary Risk Assessment for Tight Gas Development
Authors: Heslop D.O. , Schuler S. , Calvo J.J. , Copeland D.L. 
Published: December 2007

Abstract
Risk analysis can be a powerful tool for developing an overall strategy and evaluating drilling and completion alternatives for tight gas reservoirs. Instead of relying on intuitive judgment, quantitative models which incorporate the available experience can be developed to arrive at risk and economic indicators.
This paper illustrates the application of these techniques for the field development planning of the Sohlingen Dethlingen Rotliegendes tight gas reservoir in Germany, operated by Mobil Erdgas-Erdol GmbH (MEEG) in partnership with BEB Erdgas-Erdol GmbH, RWE-DEA AG and Wintershall AG. The Rotliegendes sandstone is a deep reservoir (4800 m TVD) with very low permeability (&lt;0.02 md). These reserves could not be economically developed with conventional hydraulically fractured vertical wells. A process that combines various engineering, risk and economic modeling tools was utilized to arrive at the development plan recommendations. A multi-disciplinary approach was undertaken which included the development of risked costs for the drilling, completion, stimulation and associated surface facilities for each of the candidate well configurations. The first multi-frac horizontal well in this field was very successful and produced at a rate of 20,000 m /hr. A detailed engineering effort was then undertaken to optimize the development plan for a multi-well program to efficiently recover the remaining reserves.
P. 301
Stimulation Optimization for Horizontal Wells in Carbonate Formations
Authors: Miller M.J. , Geehan T. 
Published: December 2007

Abstract
Horizontal well productivity is highly dependent on the reservoir quality as well as many drilling and completion practices. This paper discusses a process for evaluating the impact of stimulation treatments on horizontal wellbores with openhole completions in low-permeability carbonate formations in North America.
Central to the process of optimizing stimulation practices is a method for evaluating the expected productivity improvement that the horizontal wellbore should have over existing vertical wells. The technique employed uses pseud Monte Carlo simulations to generate a distribution of expected productivity improvement factors (PIFs). Stimulation or completion practices that yield PIFs substantially worse than those estimated by numerical simulations are scrutinized, and new, improved stimulation practices are implemented.
This pseudo Monte Carlo technique has been employed for several reservoirs in North America. The reservoirs include an oil reservoir undergoing waterflood, an oil reservoir undergoing CO2 alternating waterflood, and a retrograde condensate gas reservoir. Each reservoir contained horizontal wellbores that underperformed expected PIFs to different degrees. Stimulation improvements included steps to improve acid coverage along the wellbore length and careful acid system and pump schedule design to optimize etched fracture half-length and fracture conductivity. The pseudo-Monte Carlo technique was very successful at identifying low-performance stimulation practices. Reservoirs with the largest gap between expected and actual PIFs showed the greatest PIF increase when improved stimulation practices were implemented.
P. 329
What Causes Bumps in Minifrac Pressure Declines?
Authors: Shaoul Josef R. , de Pater C.J. Hans , Roodhart Leo P. , Meijers Hans C. 
Published: December 2007

Summary
Minifrac tests are performed to estimate the key design parameters prior to propped-fracture treatments: leak-off coefficient, closure stress and net fracture overpressure. It is very important, especially in the case of Tip-Screen-Out or Fracand-Pack designs, to determine these parameters as accurately as possible, since errors will enhance the chances of a premature screen-out of the propped fracture treatment.
The key parameters are determined by analyzing the pressure decline after a pump-in shut-in test. For this analysis, one assumes that the pressure falls smoothly after shut-in. However, in many cases a momentary increase is observed in the wellhead pressure after shutting in the pumps, which could compromise reliable interpretation of the pressure decline. In order to determine the cause of the pressure bump, we examined a group of mini-frac data sets which exhibited this anomalous behaviour and mini-fracs in comparable wells that showed a normal decline.
We found that the cause of the pressure bump was severe under displacement of crosslinked gel at the end of pumping the mini-frac. The crosslinked gel at the bottom of the well- bore may create a plug, which effectively makes the wellbore a closed vessel disconnected from the fracture. Heating of the relatively incompressible fluid in the isolated wellbore section then causes the pressure to increase until the yield strength of the crosslinked gel has been overcome and the plug starts to move downwards. This explains the observed bump in the pressure decline plot.
To avoid this bump it is recommended to displace the crosslinked gel to the perforations or even slightly overdisplace. In our experience, if a pressure bump is still observed, it is best to check the calculated and measured displacement volume and repeat the minifrac. If this is impossible, the simplest correction for the pressure bump is to use the initial pressure decline before the bump, and shift the final decline after the bump downwards by the magnitude of the bump. However, this procedure would be invalid if the point of fracture closure coincides with the bump.
P. 385