bluuebunny/crossref_metadata_2025 huggingface dataset:
Slickline Power Unit on Coiled Tubing Provides Innovative Solution for Setting a Nippleless Lock in a Multilateral Completion
Authors: Hall J. B. , Wijngaards B. M.
Published: December 2007

In the procedure most often used for drilling laterals from horizontal completions, a retrievable bridge plug is set in the casing. The bridge plug serves as the base for orienting and setting the whipstock used to drill the window in the casing so that the drilling of the lateral section can be initiated.

In monobore completions, operators can drill lateral sections through the tubing, and if coiled tubing drilling technology is used, this procedure can often be performed without killing the well and pulling the in-place completion. Drilling the horizontal lateral with the well flowing offers the advantages of efficient removal of the cuttings and reduced formation permeability impairment.

The retrievable bridge plug commonly used when being set with coiled tubing is the inflatable bridge plug. This plug can be run through most tubing restrictions and the element inflated to create the seal against the casing wall. If, however, casing damage or other well conditions prevent the inflatable bridge plug from being set, the operator may be left with few viable options for completing the drilling program.

This article will discuss such a case. In this scenario, repeated attempts to set an inflatable bridge plug failed during the opera-tor's drilling program. To provide a solution, a slickline running tool and nippleless lock mandrel were adapted for use with coiled tubing. Combining the slickline running tool and lock mandrel with coiled tubing had never before been attempted. In addition to providing a cost-efficient, innovative solution for a difficult service problem, the capabilities gained by combining these technologies show promise of enlarging the scope of viable alternatives for other service needs.
Revealing the Petrophysical Properties of a Thin-Bedded Rock in a Norwegian Sea Reservoir With Logs, Core, and Miniperm Data
Authors: Flølo L. H. , Kjærefjord J. M. , Arnesen D. M. , Menard W. P. , Weissenburger K. W.
Published: December 2007

An unconventional thin-bed analysis based on logs, core, and miniperm data was needed to calculate the petrophysical properties of a reservoir under development in the Norwegian Sea. More than half of the reservoir section under investigation is composed of heterolithic facies: thinly interbedded sandstone and mudstone layers from one to several centimeters in thickness and of variable quality. By using miniperm measurements with 1-cm spacing on slabbed core, it was possible to resolve the properties of the rock far below the vertical resolution of conventional wireline logs and relate them to the bulk log measurements.
Sand Production on Water Injectors: How Bad Can It Get?
Authors: Santarelli F. J. , Skomedal Eiliv , Markestad Per , Berge H. I. , Nasvig Hâvard
Published: December 2007

In this paper we present a field case based upon a reservoir operated by Statoil in the Norwegian Sea. The case concerns a series of water injectors-i.e., both subsea and platform-that underwent extreme losses of injectivity over short periods of time. When worked over, the wells showed extreme amounts of sand fill that sometimes were several hundreds of meters above the top perforation. The link between well shut-ins and injectivity losses was clear right from the onset of the study.

The life of the injectors is thoroughly reviewed and the reasons for the injectivity losses are established.

First, it is shown that even under no flow conditions corresponding to shut-in periods, the rock around the wells is too weak to sustain the stresses and fails. Second, it is established that, because of permeability heterogeneity, the wells crossflow during shut-in periods, hence allowing sand to be produced in front of the perforated interval. Third, it is shown that under routine operation conditions the particles produced in front of the perforated intervals are not able to settle in the rathole before injection restarts and hence plug the perforation tunnel upon injection restart. Finally, it is demonstrated that, during a standard shut-in, pressure waves as large as 80 bar are generated because of the so-called water hammer effect that hits the formations as a seismic wave would do. As a consequence, the formation already weakened by sand production undergoes liquefaction that triggers large amounts of sand to be released in the well, thus killing totally its injectivity.

Finally, we present how the operating conditions of the wells were successfully changed to avoid repetition of the problems experienced previously.
A New Design of Steady-State Type Experiments for Simultaneous Estimation of Two-Phase Flow Functions
Authors: Urkedal H. , Ebeltoft E. , Nordtvedt J. E. , Watson A. T.
Published: December 2007

We have developed a new design of steady-state type experiments for simultaneous estimation of relative permeability and capillary pressure functions (collectively called multiphase flow functions) from measured pressure-drop and production data. The multiphase flow functions are represented by B-splines to ensure a flexible representation, and the coefficients in the representation are determined using a regression-based approach. The methodology is demonstrated using synthetic data. Further, we show that both relative permeability and capillary pressure functions can be estimated, and we were able to reconcile all pressure-drop and production data from the steady-state type experiment conducted. An analysis of the accuracy of the estimated functions showed that they were accurately determined over a large saturation interval.
Identification and Exploitation of a High-Producing Field Extension With Integrated Reservoir Analysis
Authors: Waite M. W. , Weston J. R. , Davis D. W. , Pearn C. J.
Published: December 2007

The Wafra field is located in the partitioned neutral zone between Kuwait and Saudi Arabia. The field produces oil from the Ratawi oolite reservoir, which has been under production since 1956. Barriers to fluid movement have severely restricted aquifer support to the overlying carbonate grainstone reservoir, leading to production-induced pressure depletion and low recovery rates. Creative integration of three-dimensional seismic aspects, well log stratigraphy, and engineering analysis revealed an unexploited reservoir extension that is more open to aquifer pressure support. Wells drilled along this extension are expected to yield higher initial production rates and longer sustained production. The model was used to drill two successful step-out wells that have increased field production by over 12,000 BOPD. Eight of ten additional wells have now been drilled as a follow-up to this success. This paper reviews the case history with a focus on the multidisciplinary integration that led to opportunity identification and exploitation.
Oil-Water Displacements in Microscopic Capillaries
Authors: Templeton C.C. , Rushing S.S.
Published: December 2007

Methods previously developed for the study of liquid displacements in microscopic capillaries (inner diameters of 3 to 40 microns) have been used to investigate oil-water displacements in capillaries initially filled with water. Displacement calculations assuming perfect displacement and no capillary pressure hysteresis yielded oil effective viscosities smaller than the macroscopic viscosities. For a given liquid pair, the oil effective viscosity decreased both with decreasing capillary size and with increasing oil-water viscosity ratio. This behavior can be explained by the existence of an annular water film (20 Å to 260 Å thick) on the capillary wall.

When the capillary was first filled with oil, the ratio of the oil effective viscosity to the normal oil viscosity was highest for the first water displacement and decreased with subsequent displacements. Sometimes the oil effective viscosity ratio during the initial water displacement was greater than unity.

Introduction

In a previous paper, a technique was described for studying air-liquid and liquid-liquid displacements in very small capillaries of uniform diameter, in the hope that such microscopic data would further the understanding of the nature of multiphase fluid flow through porous media. That paper contained comprehensive data for air-liquid displacements in Pyrex capillaries, with a few data for oil-water displacements in capillaries initially filled with water.

The purpose of this paper is to present more complete results for oil-water displacements in capillaries initially filled with water, and to describe for the first time such observations in capillaries initially filled with oil. In this way the effect of the wetting history of the system upon the displacement process may be studied.

Methods

The basic techniques employed were described in the previous paper. The measuring procedure and the working equations will be briefly summarized here and a few modifications will be pointed out. For the present study, temperature control within 0.1 degrees C was obtained by placing the microscope and its immediate accessories in a thermostated air bath made of a steel frame covered with plexiglas.
Evaluation of Frac and Pack Completions and Future Outlook
Authors: Ayoub J. A. , Barree R. D. , Chu W. C.
Published: December 2007

Frac and pack introduced in the early 1990's in the Gulf of Mexico has become a well-established completion procedure aimed at enhancing the productivity of gravel packed wells. The technique consists of incorporating a "tip screenout"1 hydraulic fracturing treatment as part of the gravel packing procedure, thus stimulating the well. However, published well test data, although showing generally better productivity than classic gravel packs, presents positive skin values indicating near-wellbore damage and often questioning the existence of a fracture intersecting the wellbore.

This paper quickly reviews published data and outlines a methodology which integrates the analyses of the fracture placement data and the well test data. This integration results in a more realistic modeling of the system well and reservoir and characterizes the hydraulic fracture intersecting the wellbore.

It is shown that poor fracture conductivity and/or high fracture face skin damage coupled with wellbore storage can reproduce the behavior observed in well test data and commonly interpreted with a nonfractured model. The effects of additional pressure losses across the gravel pack can also be incorporated for a more realistic modeling. Field examples are discussed to illustrate the technique and a quick outlook of how completions of unconsolidated sandstones may evolve is presented.
Effect of Pressure Depletion on Fracture-Geometry Evolution and Production Performance
Authors: Mukherjee Hemanta , Poe B. D. , Heidt J. H. , Watson T. B. , Barree R. D.
Published: December 2007

A fractured well performance evaluation study, in the Frontier formation of the Moxa Arch area (southwestern Wyoming), revealed pressure depletion due to older 640- and 320-acre-spaced producers along the NE-SW diagonal in 640-acre sections. This was confirmed by six buildup tests across these sections. Reservoir simulation also showed that the production decline of some of these old, 320-acre-spaced wells causes enough pore pressure depletion to affect the fracture geometry in the new 160-acre infill offsets on the other diagonal in the same section. This paper presents the simulated pore pressure distribution in the drainage area of these older wells validated by buildup tests and their effects on the principal effective stress field and consequent fracture-geometry evolution around the newer wells.

The present paper also shows that depending on the location of the new well in the depleted zone and the original azimuth of the induced fractures, the newly created fracture may be asymmetric with only one wing of the fracture extending into the depleted area developing significant length and conductivity. This happens at the cost of development of the other fracture wing. Such asymmetric development of fracture wings can negatively impact production, in addition to the production loss due to actual reservoir pressure depletion.
Stimulation of Water-Disposal Wells Using Acid-in-Diesel Emulsions: Case Histories
Authors: Nasr-El-Din H. A. , Al-Anazi H. A. , Mohamed S. K.
Published: December 2007

Two wastewater disposal wells in a carbonate reservoir in Saudi Arabia suffered loss of injectivity due to severe formation damage. A thorough experimental study was conducted to evaluate the use of acid-in-diesel emulsions to stimulate these wells, which had several tight zones. The emulsified acid consisted of 70 vol% of 15 wt% HCl, 30 vol% diesel, and an emulsifier. This is the first time emulsified acid has been used to stimulate disposal wells.

Experimental results indicated that the acid-in-diesel emulsion behaved as a shear-thinning fluid. The stability and reaction rate of the acid with reservoir rocks were found to be a function of emulsifier concentration. Coreflood results showed that the emulsified acid formed wormholes in tight carbonate cores. Permeability ratio (final/initial) of reservoir cores increased exponentially with the acid injection rate.

The acid-in-diesel emulsion was used to acidize both disposal wells. The treatment included an in-situ gelled acid stage for acid diversion, and an emulsified acid stage to create deep wormholes in the reservoir. The treatment was very successful and the injectivity of both wells has significantly increased. Field data indicated that longer soaking times were needed to stimulate disposal wells. This is to ensure complete acid spending.
Prediction of Slug Frequency for Gas/Liquid Flows
Authors: Zabaras G. J.
Published: December 2007

During slug flow, knowledge of the slug frequency is essential for the gas-liquid receiving facility design as well as for predicting various slug flow characteristics such as slug length and pressure drop. Various methods proposed in the literature for predicting the slugging frequency in horizontal and inclined pipes were examined. These included both empirical correlations as well as mechanistic models. Slug flow frequency data taken with an air-water system in a laboratory flow loop together with data from the published literature were compared to the predictions of the various methods. A total of 399 data points were collected covering pipe diameters from 1 to 8 in. and inclinations from 0 to 11° above the horizontal. A total of eight published methods were compared to the data but none was found satisfactory. For this reason, the mechanistic slug frequency model of Taitel and Dukler1 was investigated in detail as an alternative unbiased prediction method. This model required the solution of the unsteady-state equations for mass and momentum by a finite difference technique. This numerical model gave satisfactory results at the expense of considerable computer CPU time. For faster slug frequency calculations a new correlation was developed utilizing all 399 data points. This resulted in 0% average error (bias) and 60% average absolute error. This correlation represents a significant improvement in slug frequency prediction accuracy over the other methods studied.
Liquid Carry-Over in Gas/Liquid Cylindrical Cyclone Compact Separators
Authors: Chirinos W. A. , Gomez L. E. , Wang Shoubo , Mohan R. S. , Shoham Ovadia , Kouba G. E.
Published: December 2007

The liquid carry-over phenomenon in gas-liquid cylindrical cyclone (GLCC©**) compact separators has been studied experimentally and theoretically.

Experimental data have been acquired including the operational envelope for liquid carry-over and percent liquid carry-over beyond the operational envelope. The data show that at low gas and high liquid flow rates, under churn flow conditions in the upper part of the cylindrical cyclone, a large amount of liquid can be carried over relatively easily. On the other hand, at high gas and low liquid flow rates, under annular flow conditions, one should exceed the operational envelope significantly in order to have large amount of liquid carry-over.

A mechanistic model has been developed for the prediction of the percent liquid carry-over beyond the operational envelope for churn flow conditions. An existing model for the prediction of the operational envelope for liquid carry-over has been extended to high-pressure conditions, including improved models for zero-net liquid flow holdup, droplet region and blowout and critical velocities.

Comparisons between the new mechanistic model predictions for percent liquid carry-over with the experimental data, under churn flow conditions, show good agreement. Also, considering the lack of experimental data, the predictions of the operational envelope for liquid carry-over at high-pressure conditions show reasonable trends.
Analysis of Post-Audits for Gulf of Mexico Gravel-Packed Oilwell Completions Leads to Continuous Improvement in Completion Practices
Authors: Pashen M. A. , McLeod H. O.
Published: December 2007

Final production rate alone is not an adequate measure of the success of a well completion. Rather, we must estimate the "po-tential" of a reservoir and judge the ultimate success of a completion on how close we come to achieving this potential. Specific productivity indexes (SPI's) [(BFPD/ft)/psi], specific injectivity indexes (SII'S) [(BFPD/ft)/psi], and completion efficiencies (CE's) (percent of Darcy radial flow) can be calculated at various times throughout a well completion. Analysis of these data quantifies the efficiency of the completion after each individual completion operation, allowing a determination of the effects of each completion practice to be made. In addition to completion efficiency data, a comparison of gravel placement volumes behind casing helps quantify optimum gravel packing procedures.

Twenty-two Gulf of Mexico completions have been analyzed using this technique. In this paper we will give details of the results of this analysis, in particular the productivity effects of various methods of underbalanced perforating, gravel packing, and well control. Items of discussion include the effects of underbalanced perforating on well performance, the effects of flowback after perforating on perforation tunnel cleaning, productivity impacts of various types of well control methods following perforating and gravel packing, and comparisons of gravel pack design parameters and gravel placement behind casing.
Experimental Investigation of the Influence of Perforating on Gravel-Pack Impairment
Authors: Blok R. H. J. , Welling R. W. F. , Behrmann L. A. , Venkitaraman Aadinathan
Published: December 2007

Analysis of the performance of perforated, gravel-packed wells compared with openhole gravel-packed wells has indicated that the perforation could be responsible for the low productivity of internally gravel-packed wells. A series of laboratory experiments on weak rock [unconfined compressive strength (UCS) = 1,200 psi] was conducted to quantify this. Castlegate sandstone rock samples, 7-in. diameter and 18-in. long, were perforated with shaped charges under downhole conditions. The perforations were gravel packed by circulating a gravel slurry past the tunnel entrance while applying a differential pressure. The pre-perforation, post-perforation and post-gravel-pack productivities of the core samples were monitored at different flow rates (5 to 20 B/D/perf). Sectional photographs of the core samples were taken at post-gravel-pack conditions for qualitative analysis. Performance evaluation of gravel-packed "realistic perforations" (debris and loose sand in the tunnel removed by drawdown-induced flow) vs. "ideal perforations" (debris and loose sand removed by external means) showed the post-gravel-pack productivities of realistic perforations to be much lower than ideal perforations in oil-phase as well as water-phase experiments. Injection of fluid after gravel packing only temporarily unplugged the perforation tunnel. The study shows the importance of fines- and debris-free perforation tunnels in maintaining the productivities of gravel-packed completions.
Heterogeneity, Permeability Patterns, and Permeability Upscaling: Physical Characterization of a Block of Massillon Sandstone Exhibiting Nested Scales of Heterogeneity
Authors: Tidwell V. C. , Wilson J. L.
Published: December 2007

Over 75,000 permeability measurements were collected from a meter-scale block of Massillon sandstone, characterized by conspicuous crossbedding that forms two distinct nested scales of heterogeneity. With the aid of a gas minipermeameter, spatially exhaustive fields of permeability data were acquired at each of five different sample supports (i.e., sample volumes) from each block face. These data provide a unique opportunity to physically investigate the relationship between the multiscale cross-stratified attributes of the sandstone and the corresponding statistical characteristics of the permeability. These data also provide quantitative physical information concerning the permeability upscaling of a complex heterogeneous medium. Here, a portion of the data taken from a single block face cut normal to stratification is analyzed. The results indicate a strong relationship between the calculated summary statistics and the cross-stratified structural features visibly evident in the sandstone sample. Specifically, the permeability fields and semivariograms are characterized by two nested scales of heterogeneity, including a large-scale structure defined by the cross-stratified sets (delineated by distinct bounding surfaces) and a small-scale structure defined by the low-angle cross-stratification within each set. The permeability data also provide clear evidence of upscaling. That is, each calculated summary statistic exhibits distinct and consistent trends with increasing sample support. Among these trends are an increasing mean, decreasing variance, and an increasing semivariogram range. The results also clearly indicate that the different scales of heterogeneity upscale differently, with the small-scale structure being preferentially filtered from the data while the large-scale structure is preserved. Finally, the statistical and upscaling characteristics of individual cross-stratified sets were found to be very similar because of their shared depositional environment; however, some differences were noted that are likely the result of minor variations in the sediment load and/or flow conditions between depositional events.
Lessons Learned From 4D Projects
Authors: Waggoner J. R.
Published: December 2007

Time-lapse three-dimensional, or four-dimensional (4D), seismic has been under consideration by the industry for reservoir monitoring for more than a decade. It offers the possibility of identifying the interwell distribution of bypassed and untapped oil, of monitoring displacement heterogeneity, and of detecting uneven pressure depletion away from wells. If obtained, these detailed observations could be used to increase ultimate recovery, reduce production costs, and prevent surprises such as unexpectedly early breakthrough.

But these benefits are not easily obtained, and are certainly not guaranteed. There are a number of factors that impact whether a 4D project will be successful, and a careful study of these is required to give a realistic expectation of what 4D can do for a specific reservoir. Numerous 4D seismic projects have been active over oil fields world wide, and successes, relative to each project's objectives, have been realized by field operators using a wide variety of data acquisition techniques (land, streamer, and seabed methods), and over a variety of field types, including both clastics and carbonates.

This paper draws from this experience to present a generalized 4D project workflow, and reviews results from some of these recent projects as illustrations. In general, sufficient software tools, rock physics data, and experience now exist to conclude that 4D is a low-risk/high-benefit reservoir management tool. The key to a successful project, however, is determining what 4D can do in a specific field, which requires a careful feasibility study, clear reservoir management objectives, and high-quality and experienced seismic processing and interpretation.
Two-Phase Isentropic Compressibility and Two-Phase Sonic Velocity for Multicomponent-Hydrocarbon Mixtures
Authors: Firoozabadi Abbas , Pan Huanquan
Published: December 2007

Two-phase compressibility and two-phase sonic velocity of hydrocarbon mixtures are needed for a variety of applications in well testing, metering, and seismic exploration. In this work, a thermodynamic model is presented to estimate the two-phase isentropic compressibility and two-phase sonic velocity. The model accounts for the mass transfer between the equilibrium phases and the effect of capillary pressure. The results reveal that isothermal and isentropic compressibilities can be different by a factor of 20 in the two-phase near the retrograde dewpoint. With the exception of the retrograde dewpoint, the difference between the isentropic compressibility in the single phase and two phase is less than the corresponding difference for the isothermal compressibility.

The sonic velocity in the two phase can be either less or more than the single phase. For the hydrocarbon mixtures that the sonic velocity decreases in the two phase, the decrease is much less pronounced than in nonhydrocarbon systems such as water-steam and water-air.
Upscaling, Gridding, and Simulating Using Streamtubes
Authors: Portella R. C. M. , Hewett T. A.
Published: December 2007

This paper presents an innovative upscaling methodology based on a semianalytical streamtube technique. The methodology generates a coarse grid based on streamtubes and isobars, whose up-scaled properties are accurately calculated using the properties of each streamtube that constitutes the coarse block. Beyond the calculation of upscaled static properties of the grid, the methodology also calculates upscaled relative permeability curves, or pseudofunctions, using a semianalytical streamtube method to perform this without requiring any significant additional time. Tests showed that the results from the streamtube coarse grid had a good agreement with the fine grid solution. In contrast, simulations with a coarse grid upscaled with conventional techniques had a bad performance in many situations. Although this upscaling methodology is heavily based on a fixed streamtube simulation method, it provided good results even for situations in which streamtube simulation techniques are not supposed to work well, such as displacements that consider gravity and compressibility.
Precipitation of Chromium Acetate Solutions
Authors: Zou Bin , McCool C. S. , Green D. W. , Willhite G. P. , Michnick M. J.
Published: December 2007

Chromium(III)-polymer systems are often used in permeability modification treatments. The transport of chromium(III) in-depth in porous rocks is sometimes limited due to precipitation. Precipitation is caused by the increase in the solution pH because of fluid-rock interactions, particularly in carbonate rocks. This paper presents experimental data on the rate of precipitation of chromium from chromium(III) acetate solutions. Experimental data were obtained for the precipitation of chromium from chromium acetate solution at constant pH. Data were obtained as a function of pH, temperature, salinity, and OAc/Cr mole ratio. The pH range studied was between 7 and 10, and the temperature range was between 25 and 45°C. Precipitation of chromium was preceded by an induction period where there was no change in concentration. The induction period decreased from 1,200 minutes at pH 7 to less than 200 minutes at pH 10 at 25°C. A higher temperature increased the precipitation rate. Precipitation is delayed by the addition of acetate ion. Both the salinity and salt type have significant effects on the rate of precipitation. A kinetic model was developed to describe both the induction period and the rate of precipitation of chromium from a chromium acetate solution in 1% KCl at 25°C for a pH range of 7 to 10 with OAc/Cr mole ratios between 3 and 9.
Shallow Water Flow Planning and Operations: Titan No. 1 Exploration Well, Deepwater Gulf of Mexico
Authors: Schuberth P. C. , Walker M. W.
Published: December 2007

Shallow water flows (SWF) from overpressured aquifers have been a persistent problem in the deepwater Gulf of Mexico (GOM) and can create significant financial and operational risks for exploration and development drilling programs. For the GOM, SWF intervals typically occur between 300 and 2,500 ft below mudline (BML) and in water depths greater than 1,500 ft. If left unchecked, the disturbance from the water flow can cause loss of soil strength surrounding the wellbore, thereby compromising the structural integrity of the well. In industry, extreme cases have led to collapsed casing and/or total loss of wellbores.

This paper details the up-front planning efforts implemented and the operational procedures utilized to successfully mitigate a SWF event experienced at the Titan No. 1 exploration well drilled in Garden Banks Block 785 (GOM), in 4,640 ft of water. Operations at Titan were based on the philosophy that performing a shallow hazards assessment, preparing and implementing SWF contingency plans, drilling a 9|-?. pilot hole (for dynamic kill), identifying a SWF zone quickly, controlling a water-flow zone with weighted mud (while drilling riserless), and using nitrified foam cement to seal off a water flow behind 20-in. conductor pipe, were all critical in successfully containing and drilling through a SWF occurrence.
The Development of Heavy Oil Fields in the United Kingdom Continental Shelf: Past, Present, and Future
Authors: Jayasekera A. J. , Goodyear S. G.
Published: December 2007

In this paper we review progress made in developing United Kingdom Continental Shelf (UKCS) heavy oil fields. Reservoir productivity is compared with existing light oil developments and three categories of heavy oil reservoir are identified, which require the application of different well technologies to achieve acceptable offshore production rates. Case histories from existing developments and fields under appraisal are used to illustrate how advances in technology and effective risk management allow increasingly difficult heavy oil fields to be developed. Finally, the future direction for these heavy oil developments is discussed, looking at the scope for improved oil recovery (IOR) techniques and further technology developments to drive down costs and to increase reserves in fields currently under waterflood or to improve the economics of hitherto subeconomic fields.
The Effect of Geological and Geomechanical Parameters on Reservoir Stress Path and Its Importance in Studying Permeability Anisotropy
Authors: Khan M. , Teufel L. W.
Published: December 2007

Reservoir stress path is defined as the ratio of change in effective horizontal stress to the change in effective vertical stress from initial reservoir conditions during pore-pressure drawdown. Measured stress paths of carbonate and sandstone reservoirs are always less than the total stress boundary condition (isotropic loading) and are either greater or less than the stress path predicted by the uniaxial strain boundary condition. Clearly, these two boundary-condition models that are commonly used by the petroleum industry to calculate changes in effective stresses in a reservoir and to measure reservoir properties in the laboratory are inaccurate and can be misleading if applied to reservoir management problems. A geomechanical model that incorporates geologic and geomechanical parameters was developed to more accurately predict the reservoir stress path. Numerical results show that reservoir stress path is dependent on the size and geometry of the reservoir and on elastic properties of the reservoir rock and bounding formations. In general, stress paths become lower as the aspect ratio of reservoir length to thickness increases. Lenticular sandstone reservoirs have a higher stress path than blanket sandstone reservoirs that are continuous across a basin. This effect is enhanced when the bounding formations have a lower elastic modulus than the reservoir and when the reservoir is transversely isotropic. In addition, laboratory experiments simulating reservoir depletion for different stress path conditions demonstrate that stress-induced permeability anisotropy evolves during pore-pressure drawdown. The maximum permeability direction is parallel to the maximum principal stress and the magnitude of permeability anisotropy increases at lower stress paths.
NMR Relaxation of Clay/Brine Mixtures
Authors: Matteson A. , Tomanic J. P. , Herron M. M. , Allen D. F. , Kenyon W. E.
Published: December 2007

Effective interpretation of nuclear magnetic resonance (NMR) logs in shaly sands requires an understanding of the NMR contribution of clays. Of particular importance is the role of clays in the rapidly relaxing part of the NMR signal.

In this study we measured the transverse relaxation time spectrum (T2) of brine mixed with four clays (illite, smectite, kaolinite and glauconite) as a function of compaction. The Larmor frequency was 2 MHz and the echo spacing 0.16 ms. Mild compaction was achieved by centrifuging the clay slurry at three successive pressures ranging from 1 to 125 psi. Highly compacted samples were produced in a uniaxial press at six sequential pressures ranging from 500 to 16,000 psi.

Each clay/brine slurry and its associated compacted sample showed a single peak in the T2 distribution spectrum. A second peak, which could be interpreted as the "clay-bound water," was never observed. The T2 peak position shifted to faster relaxation times as compaction increased, in proportion to the pore volume-to-surface ratio, Vp /As. The single peak and Vp /As proportionality are consistent with fast diffusion between the pore water and the monolayer of water on the clay surface. Surface relaxivity varied among the four clay minerals; glauconite, the clay with the highest magnetic susceptibility and iron content had the largest surface relaxivity.

These results have important implications for the interpretation of NMR logs in shaly sands. Because of the effects of compaction and to a lesser extent the iron content on a clay's T2 peak position, it is not possible to independently determine clay type from some characteristic relaxation time. These data also imply that it is not feasible to estimate the cation exchange capacity from a single time cutoff of the T2 distribution without additional information such as laboratory measurements or other log data.
Frontal Drive Production Mechanisms - A New Method for Calculating the Displacing Fluid Saturation at Breakthrough
Authors: Stutzman L.F. , Thodos George
Published: December 2007

A new graphical method, which is a modification of that proposed by Buckley and Leverett, is presented for the determination of the displacing fluid saturation at breakthrough for frontal drive mechanisms. This method is applicable to all types of fluids, which may be either soluble or insoluble in the oil at reservoir and injection conditions. This adaptation has unique advantages in handling problems in which either liquids or gases are the displacing fluids.

Introduction

In the displacement of oil from a reservoir with water or gas injected into the formation or by the expansion of a gas cap, the determination of breakthrough or flood advance is important to define the initial and subordinate phases of the operation. Thus, the determination of the displacing fluid saturation at breakthrough is fundamental to the establishment of over-all reservoir production. Methods for analyzing this saturation and for calculating production rates have been previously reported. All of these methods utilize the rate equation for linear flow developed by Buckley and Leverett.
A Computationally Efficient, Transient-Pressure Solution for Inclined Wells
Authors: Ozkan E. , Raghavan R.
Published: December 2007

This work provides an efficient algorithm to compute transient pressure responses of inclined wells. The solution is derived in the Laplace domain and cast into computationally efficient forms for all inclination angles. The algorithm allows the computation of pressures and derivatives at the wellbore as well as at observation points. Short- and long-time approximations for the evaluation of pressure responses are also provided. The long-time approximation is used to derive a general pseudoskin expression that is applicable for all inclination angles. Example computations are presented in the forms of tables and figures to display the efficacy, accuracy, and the practical use of the algorithm.
A Semi-Analytic (p/z) Rate-Time Relation for the Analysis and Prediction of Gas Well Performance
Authors: Ansah J. , Knowles R. S. , Blasingame T. A.
Published: December 2007

In this paper we present a rigorous theoretical development of solutions for boundary-dominated gas flow during reservoir depletion. These solutions were derived by directly coupling the stabilized flow equation with the gas material balance equation. Due to the highly nonlinear nature of the gas flow equation, pseudopressure and pseudotime functions have been used over the years for the analysis of production rate and cumulative production data. While the pseudopressure and pseudotime functions do provide a rigorous linearization of the gas flow equation, these transformations do not provide direct solutions. In addition, the pseudotime function requires the average reservoir pressure history, which in most cases is simply not available.

Our approach uses functional models to represent the viscosity-compressibility product as a function of the reservoir pressure/z-factor (p/z) profile. These models provide approximate, but direct, solutions for modeling gas flow during the boundary-dominated flow period. For convenience, the solutions are presented in terms of dimensionless variables and expressed as type curve plots. Other products of this work are explicit relations for p/z and Gp(t). These solutions can be easily adapted for field applications such as the prediction of rate or cumulative production.

We also provide verification of our new flow rate and pressure solutions using the results of numerical simulation and we demonstrate the application of these solutions using a field example.
Geostatistical Quantification of Geological Information for a Fluvial-Type North Sea Reservoir
Authors: Caers J. K. , Srinivasan S. , Journel A. G.
Published: December 2007

Accurate prediction of petroleum reservoir performance requires reliable models of the often complex reservoir heterogeneity. Geostatistical simulation techniques generate multiple realizations of the reservoir model, all equally likely to be drawn. Traditional to geostatistics, geological continuity is represented through the variogram. The variogram is limited in describing complex geological structures as it measures correlation between rock properties at two locations only: it is a two-point statistic. Reservoir analogs such as outcrops can serve as training images depicting the interpreted geological structure. Due to scarcity of well data, the variogram models are often borrowed from such training sets. However, the same training images could be utilized to extract more complex information in the form of multiple-point statistics measuring the joint dependency between multiple locations.

This paper compares a traditional variogram-based geostatistical model vs. a novel geostatistical method utilizing multiple-point statistics borrowed from training images. The comparison is made on the basis of flow performance for a typical North Sea reservoir. To obtain such comparison a "true" reference reservoir is generated using object-based simulation that depicts the complex intertwining of fluvial channels. Next, a different but similar reservoir is generated, termed the "training reservoir." The latter is used to extract the necessary structural information, be it variograms or multiple-point statistics, to build multiple geostatistical models of the true reservoir conditioned to sparse well data. A waterflood flow scenario with an inverted five-spot pattern is simulated using eclipse on the true reference and the various geostatistical models. Water breakthrough characteristics and water saturation distributions are used for comparison.
Optimizing Field Compressor-Station Designs
Authors: Pennybaker K. A.
Published: December 2007

The main reasons for optimizing new field compressor-station designs and for upgrading existing stations are safety considerations, environmental impacts, and economics. With a well-designed compressor station it is possible to improve safety and environmental conditions while saving capital and increasing income.

A well-designed compressor station will be able to reduce the venting of heavy hydrocarbons from storage tanks, which can increase safety by reducing the possibility of forming explosive vapor clouds near venting tanks. An optimized design can improve safety by reducing the amount of hydrocarbon inventory located at the site. This can also save money by eliminating the need for a site to be covered by OSHA's process safety management.

Improving the environmental conditions by reducing the venting of hydrocarbons from the station's storage tanks is another advantage of a well-designed compressor station. The exhaust pollution can also be reduced by utilizing less compressor horsepower and reducing the trucking needs for station supplies and products such as methanol and condensate.

The economic advantages of an optimized compressor station include reduced operating costs and maximized product recovery. Reduction in operating costs are achieved through fuel savings from reduced horsepower requirements and reducing trucking costs. Maintenance activities are also typically less due to less horsepower, freeze ups, etc. Reducing the venting requirements means more gas is recovered as product, resulting in more income.

Evaluating and selecting the best configuration for a compressor-station design is an important decision. Many schemes have been evaluated for different situations and compared so that the most cost-effective configuration can easily be selected for new or existing station designs.
More Oil Using Downhole Water-Sink Technology: A Feasibility Study
Authors: Shirman E. I. , Wojtanowicz A. K.
Published: December 2007

In this paper we report on recent R&D progress in downhole water sink (DWS) technology resulting in the establishment of a joint industry/Louisiana State U. (LSU) project-DWS Initiative. Presented are recent case histories of DWS design and successful field trials. The results are then analyzed comparatively in view of the superiority of DWS over single conventional completions. The analysis shows that, although DWS increases production of oil, its potential for reducing production of water is unknown and remains a controversial issue among operators.

The case history analysis is followed by results from the authors' theoretical and experimental study on water-cut (WC) suppression with DWS. The study was performed by comparing WC development in single (conventional) and dual (DWS) well completions for a broad range of oil reservoirs with bottom water columns. These theoretical results are supported with experiments conducted using a laboratory physical model of a dual/single completed well-reservoir system. The results included in this paper demonstrate the persistence and irreversible nature of water cut in conventional wells compared to its flexibility and easy control in DWS completions. Defined is the range of production rates where DWS may give a sizable, up to 40%, reduction of WC. It is also shown, with calculations, how to determine the expected WC reduction for a given reservoir and well-completion design.
Stabilizing Wellbores in Unconsolidated Formations for Fracture Stimulation
Authors: Nguyen P. D. , Brumley J. L. , Dewprashad B. T. , Dusterhoft R. G. , Weaver J. D.
Published: December 2007

A wellbore stabilization system incorporating fracture stimulation has been developed and modeled in the laboratory for unconsolidated and dilatant formations. The profile of resin leakoff and penetration depth into the formation is relatively dependent on the pattern of perforations. Use of soluble particulates as a fluid-loss control agent proved to be effective in diverting resin, resulting in a uniform distribution of resin over the highly varying permeability interval. A significant drop in permeability of the near-wellbore area occurred after the resin treatment, but high productivity was re-established by connecting the wellbore with the untreated formation through highly conductive fractures. During companion testing of the resin-consolidation technique, the unconsolidated sandpack became a competent formation with compressive strength in excess of 2,000 psi. This competent material will be affected less by high drawdown pressures and stress cycling during production/shut-in cycles. The injection pressure required to fracture the consolidated wellbore showed an increase when compared to that of the untreated wellbore. Stress levels existing in the formation were shown to control the number and direction of generated fractures by passing the consolidated zone.
From Matrix Acidizing to Acid Fracturing: A Laboratory Evaluation of Acid/Rock Interactions
Authors: Bazin B.
Published: December 2007

Acid fracturing and matrix acidizing are used as well-stimulation processes for carbonated reservoirs. In matrix acidizing, a deep penetration of wormholes around the well is required; in the acid-fracturing process, fluid leak-off must be limited and wormholes are prohibited. Laboratory tests are necessary to improve the design of these operations.

Specific laboratory equipment was designed to reproduce downhole flow conditions. Matrix acidizing is a constant flow rate process, whereas acid in fracture is forced from the fracture wall to the formation, a process occurring at a constant pressure drop. This process was represented in the laboratory and a new tangential cell, aiming at working with straight acids in reservoir temperature and pressure conditions, was specially designed to handle this application. The first part of the paper presents a methodology for the evaluation of acid/rock properties. Results of acid injections at constant flow rates are compared to results obtained from injections at constant pressure drop. Experiments have been conducted with limestone core samples of different petrophysical properties. Performance of different acid formulations including straight acids, emulsions, and gels was evaluated.

Results are discussed in terms of acid propagation rates and dissolution patterns. They are analyzed using x-ray computed tomography. They are classified into wormholes, i.e., branched patterns of large extension, and compact ones. Finally, recommendations are made concerning operating conditions favorable for matrix acidizing. On the opposite, conditions are given to limit dissolution and to restrict fluid loss for the acid fracturing application.