bluuebunny/crossref_metadata_2025 huggingface dataset:
Theoretical and Experimental Bases for the Dual-Water Model for Interpretation of Shaly Sands
Authors: Clavier C. , Coates G. , Dumanoir J.
Published: December 2007

A simple petrophysical model proposed by Waxman and Smits (WS)1 in 1968 and Waxman and Thomas (WT)2 in 1972 accounts for the results of an extensive experimental study on the effects of clays on the resistivity of shaly sands.

This model has been well accepted by the industry despite a few inconsistencies with experimental results. It is proposed that these inconsistencies resulted from the unaccounted presence of salt-free water at the clay/water interface. Electrochemistry indicates that this water should exist, but is there enough to influence the results? Both a theoretical study and reinterpretation of Waxman-Smits-Thomas data show that there is.

The corresponding new model starts from the Waxman and Smits concept of supplementing the water conductivity with a conductivity from the clay counterions. The crucial step, however, is equating each of these conductivity terms to a particular type of water, each occupying a representative volume of the total porosity. This approach has been named the "dual-water" (DW) model because of these two water types—the conductivity and volume fraction of each being predicted by the model.

The DW model has been tested on most of the core data reported in Refs. 1 and 2. The DW concept is also supported by log data3 and has been successfully applied to the interpretation of thousands of wells. However, the scope of this paper remains limited to the theoretical and experimental bases of the DW model.
Stochastic Reservoir Modeling Constrained to Dynamic Data: Local Calibration and Inference of Structural Parameters
Authors: Le Ravalec-Dupin Mickaële , Hu L. Y. , Nœtinger Benoît
Published: December 2007

This paper presents a new geostatistical approach, called the general-inversion method that incorporates dynamic data (pressure transient, well production, water cut) into a reservoir model. It essentially involves two basic tools: the fast-Fourier-transform moving-average (FFT-MA) generator and the gradual-deformation method. The FFT-MA generator produces unconditional Gaussian-related fields that can be perturbed on the basis of the gradual-deformation principles. Thus, the initial structure of the realizations is preserved. Integrating these two primary algorithms within an optimization process yields the general-inversion procedure. The method has at least three significant advantages. First, unlike the traditional inverse approaches, the general-inversion method easily accounts for the constraint relative to prior geostatistical information. Second, the permeability/porosity distribution can be perturbed globally or locally. And third, the method makes it possible to condition the permeability/porosity distribution and the structural (or geostatistical) parameters (mean, variance, correlation length) at the same time. Because of these distinct capabilities, the suggested inversion scheme can qualify as a general one.

The suggested approach was applied to synthetic examples designed to address such key issues as characterization of permeability distribution, updating of a reservoir model to integrate newly obtained data, and estimation of correlation length from well data.
Interpretation of Well-Block Pressures in Numerical Reservoir Simulation(includes associated paper 6988 )
Authors: Peaceman D.W.
Published: December 2007

Original manuscript received in Society of Petroleum Engineers officeJune 16, 1977. Paper accepted for publication Dec. 20, 1977. Revisedmanuscript received April 3, 1978. Paper (SPE 6893) first presentedat the SPE-AIME 52nd Annual Fall Technical Conference and Exhibition, held in Denver, Oct. 9-12, 1977.

Examination of grid pressures obtained in thenumerical simulation of single-phase flow into asingle well shows that the well-block pressure isessentially equal to the actual flowing pressure ata radius of 0.2 x. Using the equation forsteadystate radial flow then allows calculation ofthe flouring bottom-hole pressure.

The relation between pressures measured in abuildup test and the simulator well-block pressureis derived. In particular, the buildup pressure andthe well-block pressure are shown equal at ashut-in time of 67.5 ct x2/k. This is aboutone-third the shut-in time stated by previous authors, who derived their results from an erroneousassumption concerning the significance of thewell-block pressure.

When only a single buildup pressure is observedat a different shut-in time, an adjustment to theobserved pressure can be made for matching with the simulator well-block pressure.

Introduction

When modeling reservoir behavior by numericalmethods, inevitably the horizontal dimensions ofany grid block containing a well are much larger than the wellbore radius of that well. It long hasbeen recognized that the pressure calculated for awell block will be greatly different from the flowingbottom-hole pressure of the modeled well, but theliterature contains few specific guides as to how tomake the correction.

In this study, we confine our attention tosinglephase flow in two dimensions. Consider the fiveblocks abstracted from a regular grid system(Fig.1) with the center block containing a well producingat rate q. Schwabe and Brand proposed therelationship

2 kh Pe - Pwfq = ------- -----------------,..............(1)1n(r /r) + se w

where re is taken equal to x, and pe is an effectivepressure at the"drainage radius," re, obtainedfrom4Pe = Po + Fi (Pi - Po).i=1

Schwabe and Brand did not define Fi, but seemedto imply that it be taken as zero. Thus, in theabsence of a skin effect, Eq. 1 reduces to

2 kh Po - Pwfq = ------- -------------...................(2)1n (x/r) w

The most significant treatment of this subjectuntil now was that of van Poollen et al. Theystated that the calculated pressure for a well block should be tithe areal average pressure in theportion of the reservoir represented by the block.

SPEJ

P. 183^
Optimized Reservoir Development With High-Angle Wells, El Furrial Field, Venezuela
Authors: Smith Richard W. , Colmenares Rodolfo , Rosas Eulalio , Echeverria Isaura
Published: December 2007

The El Furrial field is one of Venezuela's major field assets and is operated by PDVSA (Petroleos de Venezuela, S.A.), the national oil company. Its current production of more than 450,000 BOPD makes it a giant oil field. Development of the field, which has an average reservoir depth of approximately 15,000 ft, is in its mature stages owing to implementation of high-pressure gas injection. PDVSA has consistently followed a forward planning approach related to reservoir management. Using high-angle deviation drilling techniques allows development wells to be strategically located by penetrating the reservoir at high angles to optimize production rate, extend well life, increase reserves per well, reduce operating expenses, and reduce total field development costs.

A reservoir model was constructed and simulated with detailed reservoir stratigraphy to determine realistic potential of high-angle wells (HAW's). Five wells had been drilled as of June 2000, and the first four wells have proved the effectiveness of the design. The philosophy, modeling technique, well design considerations, problems encountered, well results, and economic criteria provide a clear understanding of the risk of this technology not previously used at this depth in Venezuela. The result was the first HAW in the deep, challenging environment of eastern Venezuela.

Results show that optimization objectives can be attained with HAW's, mainly increasing per-well production rate, maximizing per-well recovery, and extending the breakthrough time of gas or water from pressure maintenance and enhanced oil recovery projects. Well results indicate that the geological and simulation modeling technique is reliable and accurate. A pilot program shows that HAW technology provides major advantages to increase production rate and reduce the overall number of wells needed to reach production objectives. However, the project also has experienced a number of unexpected drilling problems.1

The costs associated with the total project are significant, but more importantly, this program becomes very attractive because of the long-term benefits of decreased water-cut related to current water injection; decreased gas breakthrough owing to high-pressure gas injection, and fewer wells required to meet production goals.

Technical contributions include the following:

The modeling technique of applying detailed stratigraphy to a full-scale reservoir model is accurate if performed with the appropriate objectives in mind. The application of state-of-the-art drilling techniques to attain high angles at deep drilling depth is possible; however, drilling problems caused by formation instability require more study and experience. This method can be applied to other fields in the eastern Venezuelan basin currently under, or planned to be under, enhanced recovery programs and development programs.
A Technique for Detecting Incomplete Saturation of Cores
Authors: Worthington A.E.
Published: December 2007

Cores and core plugs are cleaned, dried, and saturated with brine or oil as part of many measuring procedures. The validity of the measurements depends directly on saturation being complete without any trace of residual gas in the core. Errors introduced by residual gas vary from about a square-root dependence for formation factor, through a linear effect for porosity, to what may be a severe, larger-than-linear effect for acoustic and permeability measurements. permeability measurements. A typical saturation procedure comprises evacuation of the core to a pressure of less than 15 Pa, admission of degassed fluid to the evacuated vessel containing the cores, and imposition of at least 5 MPa hydraulic pressure on the fluid while the cores remain immersed. There is 0.18 gm/m3 air left in a vessel evacuated to 15 Pa, The solubility of air in water is 20.2 gm/m3 at atmospheric conditions; therefore, if residual air at 15 Pa in the pore space of a core dissolves in a brine that saturates the core, then that air is less than 0.9% of the solubility of air in water. Similar arguments are true for other gases; therefore, this procedure ensures no residual free-gas saturation in the core after hydraulic pressure is released. The possibility exists that the procedure actually will not be possibility exists that the procedure actually will not be conducted as planned; a valve or pump seal may leak, a gas bubble may be trapped in the brine lines, and so forth. The cores still will be fully saturated, provided the leak is smaller than the capacity of the undersaturated brine to dissolve air. The following technique can detect free-gas saturation in excess of 0.01% porosity, or 0. 12 gm/m3 of air. Thus, all significant leaks will be detected, except for a narrow range that exceeds the dissolving capacity of the brine, but by less than 0.12 gm/m3.Fig. 1 is an enlarged drawing of a glass vial that can be "saturated" along with the cores. As fluid enters the saturation, vessel, a sample of residual gas in the vapor space of the vessel is trapped in the vial when the liquid level rises above the top of the cutouts in the lower rim. At the end of the cycle, any free gas left in the vial appears as a bubble at the tip of the capillary. The visual limit for bubble detection is about 0.4 nm3, which corresponds to 0.01% porosity for a 4-ml vial. The presence of a very small gas bubble in the vial conservatively indicates incomplete saturation because the vial is a closed trap once the liquid seals the base, whereas the core itself is flushed further by displacement and imbibition as the brine level rises around the core.Any vial with a configuration similar to that shown in the figure may be used for this procedure. Such vials are readily made by a glass blower from standard borosilicate glass tubing. The only special requirement is to maintain as square an end as practical on both the inside and outside of the capillary tip to allow clear observation of any gas bubble present.
A Sand-Erosion Model for Volumetric Sand Predictions in a North Sea Reservoir
Authors: Papamichos Euripides , Malmanger Eva M.
Published: December 2007

Volumetric sand-production data from a North Sea reservoir are interpreted with respect to the applied drawdown. Two sand rates are identified: the initial sand rate related to the increase of drawdown, and the final sand rate related to the magnitude of drawdown. A sand-erosion model is also presented and used for predicting the field data, and the results compare reasonably with the field measurements.
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

The 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

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

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

We 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

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

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

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

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.
Thermally Induced Wettability Alteration To Improve Oil Recovery in Fractured Reservoirs
Authors: Al-Hadhrami Hamed S. , Blunt Martin J.
Published: December 2007

Many naturally fractured reservoirs are oil-wet; during water injection, water will not imbibe into the matrix but will flow preferentially through the fractures, resulting in very low oil recoveries. For instance, the Ghaba North field in Oman is an extensively fractured, oil-wet carbonate that has achieved only 2% recovery after more than 20 years of production.

Experiments on core from fields in Oman and elsewhere have indicated that the rock will undergo a transition from oil-wet to water-wet as the temperature increases. The temperature could be increased in a reservoir setting through steam or hot-water injection. It is proposed to inject steam or hot water to heat the matrix sufficiently, inducing a wettability change and rendering the matrix water-wet. Hot water in the fractures can spontaneously imbibe into the matrix, displacing oil and resulting in favorable oil recoveries.

A 1D model of the saturation and temperature profiles during imbibition into a matrix block is developed and solved analytically. Using Ghaba North properties, it is shown that the imbibition rate is limited by the diffusion of heat through the oil. The advancing water front is located where the rock temperature equals the transition temperature for wettability change. It is estimated that approximately 30% oil recovery could be achieved in a single matrix block after approximately 700 days. In less permeable media, the imbibition rate is limited by capillary forces, and the temperature front moves ahead of the water, resulting in slower recovery.
Gas-Cap Monitoring in High-Flow-Rate, Low-Porosity Clastic Reservoirs in Colombia Gives Big Economic Returns
Authors: Bullion David , Gonzalez Fabio , Markley Marvin E.
Published: December 2007

Cased-hole neutron logging has been in use for many years and is often used to monitor gas movement in reservoirs behind pipe. This works well in high-porosity reservoirs but is rarely successful in low-porosity reservoirs. In Colombia, there are high-flow-rate reservoirs with significant permeability but low porosity [5 to 6 porosity units (p.u.)].

The challenge was to monitor gas-cap expansion, fluid movement owing to re-injection, and voidage. At the same time, the objective was to identify low gas/oil ratio (GOR) intervals behind pipe for possible recompletion.

A number of different examples illustrate both the technique and the economic benefit of the monitoring program. Many of these wells contributed significant additional oil from bypassed zones that were initially thought to be dry gas. In some wells, the instantaneous incremental production was over 10,000 BOPD from a single recompletion.

Gas-cap monitoring in very-low-porosity reservoirs in Colombia proved to be not only feasible, but also extremely profitable by differentiating dry-gas zones from low-GOR zones.
Asphaltene Stability in Crude Oils
Authors: Rogel E. , León O. , Espidel Y. , González Y.
Published: December 2007

The influence of different factors on the asphaltene stability in crude oils was evaluated. Compositional studies and structural characterization of resins and asphaltenes were carried out to study a possible relationship between these properties and asphaltene deposition behavior. Asphaltenes were obtained by precipitation with n-heptane and characterized by elemental analysis and spectroscopic techniques. Low hydrogen to carbon ratios, high aromaticities, and high condensation of aromatic rings were the main characteristics of the asphaltenes from unstable crude oils. According to these results, the stability behavior of the asphaltenes was influenced strongly by their structural characteristics. However, it was also found that stabilization by means of a commercial inhibitor was affected by the composition of the crude oil. In particular, a high content of basic functionalities in the crude oil can be related to the decrease of the inhibitor's effectiveness (dodecylbenzene sulphonic acid). Based on these findings, some useful suggestions applicable to the oilfield operations are made.
Water Shutoff Using an Inflatable Composite Sleeve Polymerized In-Situ: A Case History on Forties Delta
Authors: Leighton J. , Saltel J. L. , Morrison J. , Welch R. , Pilla J.
Published: December 2007

A new technology based on using in-situ polymerization of composites has been developed and has been used to shut off waterproducing perforations for the first time on Forties Delta. By exploiting the deformability of an unpolymerized flexible composite and the excellent mechanical characteristics of a polymerized composite, it was possible to run an expandable patch-through tubing and set in the liner below. The principles of running the composite patch on electric wireline and the specialized surface and downhole tools are described, along with the setting procedures and events offshore.

Results of this operation have shown an inflatable composite sleeve can be used as an efficient and cost-effective solution for reducing unwanted water production.
3D Transport in Acid-Fracturing Treatments: Theoretical Development and Consequences for Hydrocarbon Production
Authors: Romero J. , Gu H. , Gulrajani S. N.
Published: December 2007

While the effect of 2D proppant transport during hydraulic fracturing has been studied extensively and debated frequently, relatively little attention has been given to acid-fracturing treatments. In addition to fluid-density differences and gravity-driven segregation, spatial variation of the acid temperature and of the rock chemical properties results in more complicated physical phenomena for acid fracturing. Acid diffusion in the fracture has been estimated empirically with no considerations made to model correctly the acid flow across the fracture width. The etched-width profile resulting from 3D flow could differ significantly from that predicted by the 1D, piston-like displacement normally included in acid-fracture simulators. An important consequence of this variation in the etched pattern is a substantially different prediction of the fracture conductivity, and hence the post-stimulation hydrocarbon production. Acid flow in the fracture can affect the outcome of reservoir stimulation and must be considered when designing acid-fracturing treatments.

The equations governing fluid flow are developed initially for a 2D pressure profile. These equations are coupled with the formulations for acid wall reaction, heat transfer, and diffusion within the framework of a P3D hydraulic fracturing simulator. The theoretical formulation for acid transport across the fracture width is presented then and coupled with the equations for 2D acid flow. The equation of acid diffusion is solved across the fracture width, hence solving the equations of fluid flow for three dimensions in the fracture. The resulting fracture geometry and conductivity are used subsequently with a reservoir simulator to illustrate the consequences of the 3D acid formulation on hydro-carbon production. Simulated and field examples are presented to illustrate the effects of 3D acid flow on the etched-width distribution and post-stimulation production.
Casing Shear: Causes, Cases, Cures
Authors: Dusseault Maurice B. , Bruno Michael S. , Barrera John
Published: December 2007

Casing impairment leads to loss of pressure integrity, pinching of production tubing, or an inability to lower workover tools. Usually, impairment arises through shear owing to displacement of the rock strata along bedding planes or along more steeply inclined fault planes. These displacements are shear failures. They are triggered by stress concentrations generated by volume changes resulting from production or injection activity. Volume changes may arise from pressure changes, temperature changes, or solids movement (solids injection or production).

Dominant casing-deformation mechanisms are localized horizontal shear at weak lithology interfaces within the overburden; localized horizontal shear at the top of production and injection intervals; and casing buckling within the producing interval, primarily located near perforations.

Mitigating casing damage usually means reducing the amount of shear slip or finding a method of allowing slip or distortion to occur without immediately affecting the casing. Strengthening the casing-cement system seldom will eliminate shear, although in some circumstances it may retard it. Proper well location or inclination, underreaming, special completions approaches, reservoir management, and other methods exist to reduce the frequency or rate of casing shear.
Application of a New Model To Analyze Leak-Off Tests
Authors: Altun G. , Langlinais J. , Bourgoyne A. T.
Published: December 2007

A leak-off test (LOT), commonly known as a formation-pressure-integrity test, is a verification method to estimate the fracture pressure of exposed formations. After cementing each casing string, a LOT is run to verify that the casing seat can withstand the wellbore pressure required to drill safely to the next casing setting depth. Fracture pressure determined from this test is used as the maximum pressure that may be imposed on that formation. Critical drilling decisions for subsequent casing setting depths are based on LOT results.

Although a LOT is a simple and inexpensive test, its interpretation is sometimes difficult, particularly in formations that give nonlinear relationships between the pumped volume and the observed pump pressure. Ideally, a straight line is obtained that reflects the total system compressibility (i.e., the drilling fluid, the casing expansion, and the wellbore expansion.) Nonlinear LOT behavior is thought to be caused by gas in the system, by borehole failure, or by leakage of drilling fluid into the cemented casing/borehole annulus. There is, however, no mathematical model explaining nonlinear LOT behavior.

In this study, a mathematical model is derived to assist in analyzing nonlinear LOT behavior. The model has been used to predict the observed nonlinear behavior of field examples. In some cases of a nonlinear LOT, the model can be used to predict the maximum fracture pressure of the formation.
Research and Development of Advanced Coiled-Tubing Construction and Performance
Authors: Urayama T. , Yonezawa T. , Hamada M. , Sugino M. , Takabe H. , Ikeda A.
Published: December 2007

This paper describes joint industry project DEA107, in which BP plc, Amoco, Eni SpA. Div. Agip, Scottish Enterprise Operations, and Japan Natl. Oil Corp. (JNOC) participated. Objectives of this project were to investigate and to report on the low-cycle fatigue phenomena of coiled tubing (CT), to present a rational fatiguelife prediction model for CT, and to develop an advanced CT which could be applied to CT drilling of deep wells. In this paper, the effect of various factors on the cyclic bending performance of parent CT materials is predicted in relation to ballooning and low-cycle fatigue phenomena; corrosion and low-cycle fatigue phenomena of CT after long-term exposure in a mud environment are discussed, followed by fatigue performance and improvement of circumferential joining techniques.

A trial section of advanced CT of 2⅜-in. outer diameter (OD) and 0.190-in. wall thickness (WT) with a total length of 3,000 ft was manufactured by means of joining short lengths of seamless tubing using the amorphous diffusion bonding (ADB) technique. A CT drilling test at the JNOC Kashiwazaki test field in Japan was completed successfully using this advanced CT.