bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Use of Rate-Transient-Analysis Modeling To Quantify Uncertainties in Commingled Tight Gas Production-Forecasting and Decline-Analysis Parameters in the Alberta Deep Basin
Authors: Luo H. , Mahiya G. F. , Pannett S. , Benham P. 
Published: June 2014

Summary
The evaluation of expected ultimate recovery (EUR) for tight gas wells has generally relied upon the Arps equation for decline-curve analysis (DCA) as a popular approach. However, it is typical in tight gas reservoirs to have limited production history that has yet to reach boundary-dominated flow because of the low permeability of such systems. Commingled production makes the situation even more complicated with multiboundary behavior. When suitable analogs are not available, rate-transient analysis (RTA) can play an important role to justify DCA assumptions for production forecasting.
The Deep-basin East field has been developed with hydraulically fractured vertical wells through commingled production from multiple formations since 2002. To evaluate potential of this field, DCA type curves for various areas were established according to well performance and geological trending. Multiple-segment DCA methodology demonstrated reasonable forecasts, in which one Arps equation is used to describe the rapidly decreasing transient period in early time and another equation is used for boundary-dominated flow. However, a limitation of this approach is the uncertainty of the forecast in the absence of extended production data because the EUR can be sensitive to adjustments in some assumed DCA parameters of the second segment. In this paper, we used RTA to assess reservoir and fracture properties in multiple layers and built RTA-type well models around which uncertainty analyses were performed. The distributions of the model properties were then used in Monte Carlo analysis to forecast production and define uncertainty ranges for EUR and DCA parameters. The resulting forecasts and EUR distribution from RTA modeling generally support the DCA assumptions used for the type curves for corresponding areas of the field. The study also showed how the contribution from the various commingled layers changes with time. The proposed workflow provides a fit-for-purpose way to quantify uncertainties in tight gas production forecasting, especially for cases when production history is limited and field-level numerical simulation is not practicable.
Bayesian Probabilistic Decline-Curve Analysis Reliably Quantifies Uncertainty in Shale-Well-Production Forecasts
Authors: Gong Xinglai , Gonzalez Raul , McVay Duane A. , Hart Jeffrey D. 
Published: June 2014

Summary
Several analytical decline-curve models have been developed recently for shale-gas wells (Ilk et al. 2008; Anderson et al. 2010; Valko and Lee 2010). However, these authors did not quantify the uncertainty in production forecasts and reserves estimates. This is important because most shale plays are in the early stages of production and virtually any method will have large uncertainty when there are limited production data available. Jochen and Spivey (1996) and Cheng et al. (2010) developed bootstrap methods that can generate probabilistic decline forecasts and quantify reserves uncertainty. Hindcasts with the modified bootstrap method (MBM) (Cheng et al. 2010) provide good coverage of the true cumulative production. However, the authors did not show they can quantify reserves uncertainty with limited production data in unconventional plays.
In this paper, we introduce a Bayesian probabilistic methodology using Markov-chain Monte Carlo (MCMC) combined with Arps' decline-curve analysis. We tested this model on two data sets: Barnett shale horizontal-well gas production with more than 7 years of history and Eagle Ford shale horizontal-well oil production with more than 1 year of history. In both cases, P50 hindcasts were very close to true cumulative production and P90 and P10 hindcasts quantified the cumulative production uncertainty reliably with as little as 6 months of production available for matching.
In this Bayesian methodology, the decline-curve parameters qi, Di, and b are assumed to be random variables instead of parameters to be modified to obtain a best fit. A Markov chain of the decline-curve parameters is constructed by use of MCMC with the Metropolis algorithm (random walk). We developed the model by performing hindcasts with the Barnett case study consisting of 197 horizontal gas wells with more than 7 years of production. The prior distribution, proposal distribution, and likelihood function were calibrated so the probabilistic decline curves quantified the cumulative-production uncertainty reliably with as little as 6 months of data. The same model was then tested with analysis of Eagle Ford shale oil production from 536 wells; the probabilistic decline curves quantified the cumulative-production uncertainty reasonably well by changing only the prior distribution.
The proposed Bayesian methodology provides a means and a workflow to generate probabilistic decline-curve forecasts and quantify reserves uncertainty in shale plays quickly and reliably. This Bayesian methodology can also be applied with other analytical decline-curve models if desired.
Well/Wormhole Model of Cold Heavy-Oil Production With Sand
Authors: Istchenko C.M.. M. , Gates I.D.. D. 
Published: June 2014

Summary
Cold heavy-oil production with sand (CHOPS) is a nonthermal heavy-oil-recovery technique used primarily in the heavy-oil belt in eastern Alberta, Canada, and western Saskatchewan, Canada. Under CHOPS, typical recovery factors are between 5 and 15%, with the average being less than 10%. This leaves approximately 90% of the oil in the ground after the process becomes uneconomic, making CHOPS wells and fields prime candidates for enhanced-oil-recovery (EOR) follow-up process field optimization. CHOPS wells show an enhancement in production rates compared with conventional primary production, which is explained by the formation of high-permeability channels known as wormholes. The formation of wormholes has been shown to exist in laboratory experiments as well as field experiments conducted with fluorescein dyes. The major mechanisms for CHOPS production are foamy oil flow, sand failure (or fluidization), and sand production. Foamy oil flow aids in mobilizing sand and reservoir fluids, leading to the formation of wormholes. Foamy oil behavior cannot be effectively modeled by conventional pressure/volume/temperature (PVT) behavior. Here, a new well/wormhole model for CHOPS is proposed. The well/wormhole model uses a kinetic model to deal with foamy oil behavior, and sand is mobilized because of sand failure determined by a minimum fluidization velocity. The individual wormholes are modeled in a simulator as an extension of a production well. The model grows the well/wormhole dynamically within the reservoir according to a growth criterion set by the fluidization velocity of sand along the existing well/wormhole. If the growth criterion is satisfied, the wormhole extends in the appropriate direction; otherwise, production continues from the existing well/wormhole until the criterion is met. The proposed model incorporates sand production and reproduces the general production behavior of a typical CHOPS well.
Analysis of Gravity Drainage
Authors: Hall H.N. 
Published: June 2014

Abstract
Various factors must be considered in an engineering evaluation of gravity-drainage reservoirs. Among these are:the effect of producing rate on total oil recovery;the effect upon well productivity and ultimate recovery of the pressure level maintained during the producing life of the reservoir;the economic advantage of full or partial pressure maintenance; andestimate of the rate of gas production and injection and the possible purchase of gas under conditions of full pressure maintenance to ascertain compressor facilities needed.
All of these factors can be evaluated only when a reliable method is employed for determining reservoir performance in gravity-drainage reservoirs.
The purpose of this paper is to present a general method for calculating the performance of a gravity - drainage reservoir. This method is applicable for conditions of complete pressure maintenance, partial pressure maintenance and normal pressure depletion. Provisions are made to take into account variations throughout the reservoir of reservoir configuration, changes in permeability and fluid composition.
Based on the method presented in this paper, an IBM 650 computer program has been developed. The past performance of an actual gravity-drainage reservoir producing under conditions of declining pressure and no gas injection was duplicated using this program.

Introduction
In tilted reservoirs the production of oil is influenced by drainage of oil from upstructure to downstructure locations. When this downstructure drainage of oil is sufficient to cause effective segregation of the gas and oil in a reservoir, the reservoir is usually classified as a segregation drive or gravity-drainage reservoir. (Discussion will be restricted to gravity-drainage reservoirs which have no encroachment of edge water.) The important feature in gravity-drainage reservoirs is the density difference between reservoir oil and gas. These phases tend to segregate in the reservoir with the result that in the gas cap the oil saturation is maintained at a higher level by drainage of oil from the gas-cap area. Oil can be produced from the oil zone at a low gas-oil ratio and reservoir energy is thereby conserved.
Stranded Gas in the Netherlands: What is the Potential?
Authors: Schulte Ruud , Lutgert Jan , Asschert Annemiek 
Published: June 2014

Abstract
In recent years, gas production in the Netherlands has peaked and appears to have gone into a slow but continuous decline. In an attempt to arrest this decline the Dutch government is investigating possibilities to tap into a previously unattractive class of reservoirs: the stranded fields.
Since the fifties, some 440 gas fields and 45 oilfields have been discovered in the on- and off-shore sectors of the Netherlands. Total gas reserves amount to over 4500 BCM of which some 71% has been produced. Oil reserves amount to 1.15 billion barrels of which 75% has been produced. From the 485 proven fields around 120 accumulations have not been developed and are considered stranded fields. Total volumes in these "contingent resources" amount to over 200 BCM GIIP and over 60 million m3 STOIIP. Tight reservoirs, distant infrastructure, small volumes, and anomalous gas qualities are amongst the main reasons why these resources have not yet been developed.
In this paper, a screening methodology will be presented showing which of these fields might still qualify for development given recent technological and economic changes. By applying a hybrid methodology of GIS tools, data-mining applications and a quick screening economic evaluation the most attractive candidates for development are highlighted. In addition, the impact of new/improved technology, CAPEX changes or tax changes on the development economics are being modeled.
In order to renew interest in these stranded fields it is the intention of the Dutch Government to share results both on the data used for the analysis and any notional development options resulting from this exercise.
Economic Optimization of a Development Program for a Low-Permeability Reservoir
Authors: Hodgson R.N. , Clark G.C. , Rowe M.D. 
Published: June 2014

Introduction
To evaluate the development of the Sacatosa field, Maverick County, Tex., which is a marginal reserve field, a complete computer study was made. The computer phase of the work was performed to determine, first, if the field could be economically developed and, if so, to determine the best completion methods and well-spacing patterns to use.
To answer these questions, a numerical solution of the two-phase flow equations developed originally by Muskat, the Howard-Fast equation for fracture extension, and an economic computer simulation model for analysis of the various economic factors involved in a field wide development program were utilized.
Prior to any of the computer work, it was necessary to conduct an extensive field-testing program to gather sufficient data for the various computer phases. This testing involved primarily the determination of initial reservoir pressure, producing bottom-hole pressure and obtaining representative fluid samples. Considerable emphasis was also placed on obtaining accurate producing GOR's; and, as a result, special metering separators were installed on three test wells. Field data also were obtained which indicated the fracture techniques used yield horizontal, single-plane fractures.
Additional data (Table 1) also were available on the reservoir properties, plus the early producing rates from a series of test wells drilled to aid evaluation of the field.

Historical Background
Three wells were drilled in 1957 to initially evaluate the field. One of these wells was unfractured and never attained production greater than 8 B/D, and this only after stimulation with 150 quarts of nitroglycerin. The other two wells were fractured - one with a 66,690-gal, single-plane treatment and the second with a dual-plane treatment, one of 17,640 gal and the other of 51,000 gal of lease crude with 1 lb of 20–40 mesh sand/gal. At the time of the computer study, these wells were the only ones available to provide any indication of production trends for an extended period. As a result, these wells were tested to provide producing bottom-hole pressures so that a check point would be available in solving the flow equations, that is, producing bottom-hole pressure after about 10,000 bbl of stock-tank oil production at an average rate of 18 B/D.
Productivity Increase Using Hydraulic Fracturing in Conventional and Tight Gas Reservoirs – Expectation vs. Reality
Authors: Rahim Zillur , Al-Anazi Hamoud , Al-Kanaan Adnan , Habbtar Ali , Al-Omair Ahmed , Senturk Nejla , Kalinin Daniel 
Published: June 2014

Abstract
Hydraulic fracturing technology is widely used to facilitate and enhance the gas recovery process from conventional and tight gas resources. Tight gas or unconventional reservoirs, that include very low permeability sandstones, carbonates, or shales, cannot be economically produced without hydraulic fracturing. Recently, much progress has taken place in the overall hydraulic fracturing procedures and the field implementations of advanced stimulation technology have produced good results. The proper selection of well trajectory, gel concentration, polymer loading, proppant type/size and concentration, perforation methods, locations for packer and frac port placement in a multistage fracturing assembly, number of fracture stages to cover the net pay, etc., have all contributed to successful stimulation and improved gas recovery. Even though stimulating gas reservoirs has become a routine application and much experience has been gained in this area, not all treatments are straightforward without problems and challenges. Unless a stimulation treatment is carefully designed and implemented, the post-stimulation results in moderate to tight reservoirs may not be encouraging, and can easily fall below expectation.
The most essential step to close the gap between expected results and actual well performance is to understand reservoir characteristics and its potential to produce at a sustained rate after a successful fracturing treatment. Overestimation of reservoir flow capacity and achieved fracture geometry will also over-predict well performance. This paper addresses the importance and impact of detailed reservoir characterization and superior stimulation processes on final well performance. Several field examples from Saudi Arabia’s gas reservoirs are presented in the paper showing the value of effective well planning, reservoir characterization, application of hydraulic fracturing, and proper cleanup.
The paper also illustrates the impact of drilling trajectory and wellbore reservoir connectivity on the proper placement of desired hydraulic fracture treatments and sustained gas production.
Fractures and Craters Produced in Sandstone by High-Velocity Projectiles
Authors: Rinehart John S. , Maurer William C. 
Published: June 2014

Abstract
The mechanics of impact crater formation in rock, particularly sandstone, has been studied, the velocity range being approximately that normally associated with oilwell gun perforators. The bullets were small steel spheres having diameters of 3/16, 9/32 and 7/16 in.; impact velocities ranged from 300 to 7.000 ft/sec. The craters have two distinct parts - a cylindrical hole (or burrow) with a diameter the same as that of the impacting sphere, and a wide-angle cup comprising most of the volume of the crater. The burrow is formed as material in front of the projectile is crushed and pushed aside, forming a cylindrical hole surrounded by a high-density zone. The cup forms as fractures are initiated in front of the projectile and propagate along logarithmic spirals, approximating maximum shear trajectories, to the free surface of the rock. A most significant observation (made for the first time) was that, below the base of the cup in one type of sandstone, there are a group of similar fractures, not extending to the surface, which are spaced uniformly a few millimeters apart. Each fracture follows roughly the contour of the base of the cup and appears to require a certain threshold impulse to initiate it. These fractures comprise a relatively high fraction of the total, newly exposed surface area. The volume of the material removed by crushing varies as the first power of the impact velocity and the volume removed by fracturing, as the second power of the impact velocity. Penetration varies linearly with the impact velocity and is inversely proportional to the specific acoustic resistance of the target material, the proportionality constant being dependent upon the shape of the projectile.
Cellar Oil
Authors: Gaskell M.H. , Lindley D.C. 
Published: June 2014

Introduction
Small, steeply inclined reservoirs without natural water drives often are found associated with salt domes or other highly faulted structures. Frequently, only one well may be economically justified in these reservoirs, from which oil is produced by an expanding gas-cap drive or by a dissolved-gas drive. Although a large fraction of the oil upstructure from the well may be recovered during primary depletion, only a small fraction of the downdip oil can be produced because of gravity effects. This downdip oil has been defined as "cellar oil"' in contradistinction to "attic oil" which is the oil above the structurally highest well in reservoirs where a natural water drive is present. In this study, two methods of producing cellar oil by water flooding a one-well reservoir were investigated by means of a laboratory model. This model was scaled to represent a prototype reservoir having an area of 30 acres, a permeability of 500 md, and a thickness and dip of 30 ft and 30, respectively. One method considered, the simultaneous injection of water and production of oil from a single well, would require that the lower portion of the productive interval of a well be completed for water injection and the upper portion for oil production. The other method considered, intermittent injection, would involve alternate injection of water into and production of oil from a single well. Injection of water into the formation would repressure the reservoir, causing gas to go back into solution. Since some of the injected water would flow updip from the well, water injection usually would be followed by a waiting period during which the water could drain from above the wellbore. Production of oil by gravity drainage and gas-cap drive could be initiated when water drainage became sufficiently complete. The amount of water produced along with the oil would naturally depend on how soon after water injection ceased that production was started. This process could be repeated in cycles until oil could no longer be produced economically.
Of these two methods, the intermittent injection technique would be simpler to put into operation since it does not require a dual completion. Also, it is probably more generally applicable than the simultaneous injection-production method. It is to be expected that in some reservoirs the rock and fluid properties would be such that practical oil-production rates could not be achieved by the simultaneous technique. However, in reservoirs where the simultaneous method will result in practical rates of oil production, it does have the advantage of permitting immediate, continuous oil production; whereas in the intermittent method, oil production is interrupted by periods of water injection and drainage. It was the objective of this study to determine whether these two methods of cellar oil production are practical for the representative prototype investigated and to evaluate their relative merits.
Unsteady-State Gas Flow into Gas Wells
Authors: Smith R.V. 
Published: June 2014

Abstract
The theory for unsteady radial flow of gas, as simplified by Aronofsky and Jenkins, has been reviewed and compared with actual well performance. This study indicated that the theory should be modified by the introduction of an empirical "rate of flow" function "Y(q)". The expansion of the theory on the flow of gas to include a Y(q) term bridges the gap between the theory of unsteady-state flow of gas and actual gas-well behavior. Apparently, the Y(q) term is a function only of the rate of flow for a given well. The completion factor or skin effect is associated with the Y(q) function in such a manner that at least two or more sets of drawdown or pressure build-up tests are needed to separate the Y(q) function and the completion factor. Since the Y(q) function used in this report represents an energy loss dependent on rate of flow near the well-bore of a gas well which is in addition to the loss required by Darcy's law, the Y(q) function is related to the exponent of the back-pressure curve for a gas well.
Techniques and equations are presented which permit the estimation of stabilized and "short-time" deliverabilities.

Introduction
The published theory of radial unsteady-state flow of gas through porous media may be divided into papers which use Darcy's law as a premise and other papers, which recognize that Darcy's law may not hold for flow into gas wells. Miller compared theory based on Darcy's law with actual gas-well behavior and concluded that flow into gas wells deviates from Darcy's law. Houpeurt in a thorough investigation of flow into gas wells concluded that the flow rate into a gas well is proportional to the difference between the squares of upstream and downstream pressures elevated to a power between 1.0 and 0.5. Houpeurt also concluded that the deviation from Darcy's law is caused by irreversible, kinetic energy exchange between the flowing gas and the porous media. Tek presented a complete evaluation of the flow problem in gas wells. Several investigators state that the inclusion of gas compressibility into flow equations based on Darcy's law does not begin to explain the flow problems suggested by gas-well behavior.