bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Effect of Producing Time on Type Curve Analysis
Authors: Raghavan R. 
Published: December 2007

This paper explores the consequences of the assumption that the producingtime is long compared to the longest shut-in time used in type curveanalysis. The fractured-well type curves of Gringarten et al. and thewellbore-storage type curves of Agarwal et al. are examined in detail.New type curves are presented. Applications of the new type curves tofield data are discussed.

Introduction
In 1970, Agarwal et al. 1 introduced the idea oflog-log type curve matching to analyze the wellborestorage effect in a well with an annular skin regionadjacent to the sandface. In the same year, Rameydemonstrated that log-log graphs can be used toidentify wellbore storage effects, acidized wells, andfractured wells, since each of these conditionsproduces a specific trace at early or short times. produces a specific trace at early or short times. Ramey defined short-time data as that obtainedbefore the conventional semilog straight line.Since 1970, other type curves have been presented.Of importance to early-time analysis are the wellborestorage type curves of Agarwal et al., McKinley, and Earlougher and Kersch and the fractured-welltype curves of Gringarten et al., Cinco et al., andArgarwal et al. Applications of the solutions toshort-time data are documented in Refs. 2, 5, 6, and10 through 14.Except for McKinley, all have examined onlydrawdown solutions. McKinley examined onlybuildup solutions. However, since he assumed thatthe producing time was much larger than the longestbuildup time, and since the application of drawdowntype curves to pressure buildup or falloff data isbased on the assumption that the longest builduptime is small compared with the producing timebefore shut-in, his results are essentially the same asthose in Refs. 1 and 6.*The assumption that the longest buildup time isshort compared with the producing time beforeshut-in implies that if a well is not produced for asufficient period then the drawdown solutions cannot beused. Unfortunately, many are not aware that thisrequirement exists. Moreover, very little quantitativedocumentation is available to indicate theconsequences of this assumption.The objectives of this paper are (1) to examinecritically the effect of producing time on the log-logtype curve procedure, (2) to establish criteria for useof the drawdown type curves, (3) to discuss errorsthat will result if proper care is not taken in analyzingdata when producing times are small, (4) todemonstrate the use of the findings of this paper bypresenting field case illustrations, and (5) to delineate presenting field case illustrations, and (5) to delineate procedures to be followed to account for producing procedures to be followed to account for producing time. For brevity, only the fractured-well type curvesof Gringarten el al. and the wellbore-storage typecurves of Agarwal et al. will be considered.
JPT
P. 1053
Correlation of Ultralow-Shear-Rate Viscosity and Dynamic Barite Sag
Authors: Dye William , Hemphill Terry , Gusler William , Mullen Gregory 
Published: December 2007

SummaryThe occurrence of barite sag has been a well recognized but poorly understood phenomenon in the drilling industry resulting in problems such as lost circulation, well control and stuck pipe. The financial impact on drilling costs, usually resulting from rig-time lost while circulating and conditioning the drilling fluid system, is not trivial. Recurring barite sag problems reportedly have resulted in the loss of drilling projects.Originally thought to occur under static conditions, barite sag is recognized now to occur more readily under dynamic, low-shear-rate conditions. Industry experts have offered a variety of measuring parameters, based upon empirical data, that only partially correlate with the occurrence of barite sag. Prediction of barite sag in dynamic flow has created an engineering challenge.The effect of shear rate on dynamic barite sag, for invertemulsion drilling fluids, has been studied and quantified using new and advanced technology. A new field viscometer capable of measuring viscosity at shear rates of 0.0017 sec−1 and an eccentric wellbore-hydraulics model were used to develop and understand this relationship. Changes in mud weight as a function of shear rate, hole angle, annular velocity (AV), and eccentricity correlate with ultralow-shear-rate viscosity.Based upon experimental results, field technology has been developed to predict the potential for barite sag of invert-emulsion drilling fluids and to provide remedial measures through ultralow-shear-rate-viscosity modification. The efficacy of using traditional rheological measurements as indicators of barite sag potential is addressed.
Lateral Proppant Distribution: The Good, the Bad, and the Ugly of Putting Frac Jobs Away
Authors: Aud W. W. , Poulson T. D. , Burns R. A. , Rushing T. R. , Orr W. D. 
Published: December 2007

Summary
This paper shows proppant-induced pressure increase (i.e., tip screenout, pack, body pack, etc.) can relate to restricted vertical and lateral proppant distribution in hydraulic fractures. The discussion focuses on interpretation of the character of the pressure response during the proppant stages. Essentially, this pressure response relates directly to the quality of the production response and the level of success. The technology presented has been found to apply to all rock types, frac packs, and low-permeability and water-frac applications.
This area of study is based on extensive engineering studies and common sense observation. Prior to publication of this work, this approach fit the reservoir engineering interpretation of the producing character and advanced fracture-treatment-pressure interpretation on a minimum of 1,000 wells. When premature proppant-induced friction occurs in the hydraulically induced fracture, lateral and vertical proppant distribution adjacent to the pay interval can be affected negatively. Restricted proppant distribution results in less effective stimulation because proppant is not distributed well both vertically and laterally adjacent to the pay interval. The fracture stimulation may have been "put away;" but the negative aspects of how the stimulation was designed and implemented may have a significant effect on the resultant production response.
To establish the basis for additional thought and investigation, there is discussion about deficiencies in overly simplified pretreatment minifracture-analysis procedures. Many of these analysis methods are not focused on the proppant-induced friction character, and therefore do not optimize proppant distribution. Discussion is provided regarding differences in the proppant-induced friction character of various fracturing fluids which is not an inherent variable typically included in fracture-treatment-design methodology.
Performance Review of a Large-Scale CO2-WAG Enhanced Recovery Project, SACROC Unit Kelly-Snyder Field
Authors: Kane A.V. 
Published: December 2007

Introduction
This paper reviews the performance of the CO2-WAG (water-alternating-gas) project conducted at the SACROC (Scurry Area Canyon Reef Operators Committee) Unit since early 1972. Numerous papers published previously describe in great detail the reservoir, previously describe in great detail the reservoir, the CO2 displacement process, the transmission of CO2 to the field, the mechanics of the operation of the project, a progress report through 1975, and other matters. Since detailed descriptions are available of reservoir characteristics, field history before the inception of the CO2 project, planning and design, and facilities installations, these subjects will be reviewed only briefly here. The performance of CO2 project itself since it began in J an. 1972 is emphasized. project itself since it began in J an. 1972 is emphasized. Kelly-Snyder Field, located in Scurry County, TX, is the major unitized field among four continguous fields along the 35- x 5-mile (56.3- x 8.05-km) Canyon Reef formation (Fig. 1). Reservoir and fluid properties are summarized in Table 1.Estimated original oil in place in the SACROC Unit area, based on a volumetric determination, was 2.73 billion STB (434 Mm3). This volume was used for the evaluation and design of the CO2 miscible flood and for early estimates of incremental oil recovery resulting from CO2 processing.In 1973, Chevron Oil Co., SACROC Unit operator conducted a 24-year history match of more than 1,500 wells in Kelly-Snyder Field using a two-dimensional black-oil simulator. On the basis of this study, the estimated original oil in place in the SACROC Unit area was reduced to 2.113 billion STB (335.9 Mm3).

History of Kelly-Snyder Field and the SACROC Unit Before the CO2-WAG
Project Project The reservoir was discovered in Nov. 1948. Subsequent development was rapid and essentially complete by Nov. 1951 when 1671 producing wells had been drilled. The production and injection history of the field is shown production and injection history of the field is shown in Fig. 2.Early production performance indicated that solution gas drive was the primary producing mechanism and that a pressure maintenance program would be required to prevent excessive loss of reserves. To improve recovery prevent excessive loss of reserves. To improve recovery the operators and royalty owners of Kelly-Snyder Field agreed to unitize to begin pressure maintenance. In 1953, the Texas Railroad Commission approved formation of the SACROC Unit.Water injection into a unique pattern involving 72 center-line injectors began Sept. 1954. Because of increased oil demand and resulting higher allowables, injection capacity had to be added beginning in 1969. During 1969-71, 72 additional wells were converted to injection service, resulting in a total of 144 center-line injectors. Operational of this center-line injection system continues presently.
JPT
p. 217
Recovery of Heavy Oil From the Monterey Formation in Offshore California by Cyclic Injection of Light-Oil Diluent
Authors: Garnett R. L. 
Published: December 2007

Summary
This paper describes a single-well pilot in which light-oil diluent was injected through tubing to lower in-situ oil viscosity and increase production from a low-gravity oil well. The pilot well is located on the Heritage platform in the Santa Ynez Unit and produces from the Monterey formation. The pilot validated laboratory data suggesting that large production-rate increases could result from high-rate diluent injection.
Recovery Correlations for In-Situ Combustion Field Projects and Application to Combustion Pilots
Authors: Brigham W.E. , Satman A. , Soliman M.Y. 
Published: December 2007

This paper presents two correlations developed to predict the fieldwide oil recovery of dry in-situ combustion processes. The correlations are based on a combination of engineering and statistical approaches. This work also discusses extension of the second correlation to pilot projects and concludes that correlation parameters used for fieldwide projects seem reasonable for use in pilot projects.

Introduction
During the last three decades, the injection of heat-bearing fluid into a reservoir has gained considerable usage as an enhanced oil recovery mechanism. Crude oils with low API gravity and high viscosity do not respond satisfactorily to conventional recovery processes. Since oil viscosity is highly temperature dependent, the performance of these reservoirs can be improved significantly by raising the reservoir temperature through the addition of heat. In-situ combustion is one of the processes that can increase oil recovery through heat addition.
Oil recovery predictions for in-situ combustion projects would provide a basis for calculating air-injected/oil-produced ratios (AOR's), oil rates, oil recovery, and economic limits. There is a possibility that such predictions could be achieved by describing the movement of heat and fluids analytically, and such approaches have been tried; however, no analytic model has been developed that completely describes the movement of heat and fluids.1
Numerical modeling has been an alternative way of describing in-situ combustion; however, due to the complexities of the process, the multidimensional geometry, and the cost of running the more complex models, no approach to recovery prediction has been entirely satisfactory.
It appeared that the solution to this dilemma was to attempt to correlate field results. Our approach was to base our correlating parameters primarily on those terms that occur in heat and material balances of combustion and only then to add additional variables on a purely statistical correlation basis. Although some screening guides2–6 in the literature attempt to define which projects may be successes or failures, these guides make only a yes/no evaluation or apply only to certain fields. Therefore, there is a clear need to develop a simple model to predict the oil recovery to be expected from in-situ combustion.
Gradient-Based History Matching With a Global Optimization Method
Authors: Gomez Susana , Gosselin Olivier , Barker John W. 
Published: December 2007

SummaryWe investigate the application of a global optimization algorithm called the tunneling method to the problem of history matching of petroleum reservoirs.Results are presented for two test cases. The first is a small synthetic case in which the global minimum is known. The second is a real field example. In both cases, a series of minima was found. The computational cost of each tunneling phase is found to be comparable with the cost of each local minimization.It is concluded that the tunneling method may have a practical application in history matching as an alternative to immediate reformulation of the problem if the first minimum found does not represent an acceptable match.
A Multiscale Approach to Production-Data Integration Using Streamline Models
Authors: Yoon Seongsik , Malallah Adel H. , Datta-Gupta Akhil , Vasco Don W. , Behrens Ronald A. 
Published: December 2007

Summary
We propose a multiscale approach to data integration that accounts for the varying resolving power of different data types from the very outset. Starting with a coarse description, we match the production response at the wells by recursively refining the reservoir grid. A multiphase streamline simulator is used for modeling fluid flow in the reservoir. The well data are then integrated using conventional geostatistics, for example sequential simulation methods. There are several advantages to our proposed approach. First, we explicitly account for the resolution of the production response by refining the grid only up to a level sufficient to match the data, avoiding over-parameterization and incorporation of artificial regularization constraints. Second, production data are integrated at a coarse scale with fewer parameters, which makes the method significantly faster compared to direct fine-scale inversion of the production data. Third, decomposition of the inverse problem by scale greatly facilitates the convergence of iterative descent techniques to the global solution, particularly in the presence of multiple local minima. Finally, the streamline approach allows for parameter sensitivities to be computed analytically using a single simulation run, thus further enhancing the computational speed.
The proposed approach has been applied to synthetic as well as field examples. The synthetic examples illustrate the validity of the approach and also address several key issues, such as convergence of the algorithm, computational efficiency, and advantages of the multiscale approach compared to conventional methods. The field example is from the Goldsmith San Andres Unit (GSAU) in west Texas and includes multiple patterns consisting of 11 injectors and 31 producers. Using well-log data and water-cut history from producing wells, we characterize the permeability distribution, thus demonstrating the feasibility of the proposed approach for large-scale field applications.
Wave Structure in WAG Recovery
Authors: Marchesin Dan , Plohr Bradley J. 
Published: December 2007

Summary
In immiscible three-phase flow, the lead oil bank can split into two, a Buckley-Leverett shock wave followed by a new type of shock wave. Such a nonclassical "transitional" shock wave is common in three-phase flow. Its sensitivity to diffusion implies that capillary pressure must be modeled correctly to calculate the flow. In particular, transitional shock waves arise in water-alternating-gas (WAG) flow. They can be calculated by semi-analytic methods, which are helpful in the design of effective WAG recovery strategies.
New Wireline Formation Testing Tool With Advanced Sampling Technology
Authors: Proett Mark A. , Gilbert Gregory N. , Chin Wilson C. , Monroe Myrick L. 
Published: December 2007

Summary
A recently introduced wireline formation-testing tool incorporates new digital-control technology that significantly improves formation fluid sampling and pressure testing. A primary focus of the new technology is improving the quality of reservoir fluid samples. An innovative pumpout design using a digital-control feedback system enables the tester to continuously monitor the fluid sampled and to make precise adjustments to the rate and pressure at which the fluid is withdrawn from the formation and injected into a sample chamber. The tool design incorporates a powerful pumpingsystem motor and an efficient hydraulic system. Consequently, invaded fluids surrounding the probes, such as mud filtrate, can be flushed 50% faster than other wireline test tools whose capabilities have been made public.1,2 Faster flushing enables quicker sampling of virgin formation fluids. Sample chambers can be filled against hydrostatic pressure to help ensure that pressure-volume-temperature (PVT) characteristics of the samples are not corrupted. Furthermore, additional pressure can be applied to minimize phase changes that might otherwise occur because of temperature gradients in the borehole. The new system also can be used to perform a closed-chamber PVT test for the bubblepoint of the fluid sampled.
Closely spaced dual probes are deployed simultaneously for pressure testing and fluid sampling. Besides increasing tool reliability through redundancy, the two probes allow for advanced pressure-testing techniques. For example, formation anisotropy can be determined with an interference test between the two probes. Alternatively, a new pressure-pulsing technique can be used, which uses time delays between the probes' measured pressures to determine additional hydraulic-diffusive properties of the formation. The drawdowns can be rate- or pressure-controlled from either probe.
The new tester is combinable with existing openhole logging tools, and tester tool sections are interchangeable. This combinability permits a complete wireline tool string to be configured to meet particular openhole formation-evaluation and testing needs in a single trip into the well. Current tool sections for the new tester include a dual-probe section (DPS), flow-control pumpout section (FPS), precision quartz gauge section (QGS), chamber valve section (CVS) for two sample chambers (1 to 5 gallons), and a multichamber section (MCS) with 1,000-cm3 chambers. The MCS chambers are compatible with hydrogen sulfide (H2S) with Natl. Assn. Of Corrosion Engineers-approved materials and have an exemption with the U.S. Dept. of Transportation (DOT) for common-carrier transportation.
This paper details operational features of the new tester and introduces new pressure-testing and sampling-interpretation techniques. Field-test results are used to demonstrate these features and techniques.
Log Core Measurements of Oil in Place, San Joaquin Valley
Authors: Neuman C.H. 
Published: December 2007

Current oil in place in an old field was measured using cores and openhole logs. Porosities calculated from logged densities were confirmed by core measurements with restored overburden pressure. Gas saturations calculated from openhole logs were confirmed by cased-hole logs. Water saturations calculated from logs are compared with core saturation measurements.

Introduction
This paper describes an effort to determine oil in place made to assess the likelihood of success of a proposed tertiary recovery project. Accurate determination of oil in place was influenced by several characteristics common to relatively shallow California sands:water salinity is low and varies with depth,clays contribute significantly to electrical conductivity,sands are loosely consolidated so that restoration of overburden pressure significantly changes core-measured properties, andthe thick formation is made up of distinct thin strata.
These factors complicate interpretation of each measurement method used: core measurements of saturations, irreducible water saturations, and porosities, plus log measurements of porosities and saturations using density, neutron, resistivity, pulsed neutron capture, electromagnetic propagation time, and nuclear magnetism logs. Confidence in the accuracy of measured porosity and fluid saturations is enhanced by the approximate agreement between measurements using different and independent physical properties.

Coring and Core Handling
Cores were obtained using a 5.2-in. (13.3-cm) drag bit in some sections of the well and a 3.625-in. (9.2-cm) conventional core bit in others. Lost circulation occurred frequently. From 563 ft (172 m) cored, 465 ft (142 m) of core was recovered. Cores were forced from the core barrel into 3-ft (0.9-m) lengths of plastic tubing and sealed with plastic caps. They then were frozen quickly to the temperature of dry ice and stored in a cold storage locker until analyzed. A slab approximately 1 in. (2.5 cm) thick cut from the core was cast in tooling plaster to enable photography and geological description and was stored to provide a permanent record.
Stress-Dependent Permeability: Characterization and Modeling
Authors: Davies J.P. , Davies D.K. 
Published: December 2007

Summary
During the production life cycle of a reservoir, absolute permeability can change in response to an increase in the net effective stress. This paper focuses on stress-dependent permeability in unconsolidated, high-porosity sand reservoirs (offshore turbidites) and moderate-to low-porosity consolidated reservoirs, including tight-gas sands. Specifically we address fundamental controls on stress-dependent permeability, rock-based log modeling of stressdependent permeability in cored and noncored wells, and, finally, implications for production rates and recovery volume based on data from reservoir simulation. Results demonstrate that the rate of reduction in permeability with an increase in stress is a function of the pore geometry in both consolidated and unconsolidated sand reservoirs.
A practical, rapid, and cost-efficient methodology is presented to improve evaluation and enhance the productivity and management of stress-dependent reservoirs. Several cases are presented of a conceptual, single-well model of an overpressured, tight-gas sandstone reservoir that include stress-dependent permeability. Results of simulation analyses for varying conditions of reservoir stress demonstrate the importance of stress-dependent permeability in more accurate forecasting of reserves and predicting optimum wellbore-producing conditions.