bluuebunny/crossref_metadata_2025 huggingface dataset:
Visualization of Oil Recovery by Water-Alternating-Gas Injection Using High-Pressure Micromodels
Authors: Sohrabi M. , Tehrani D. H. , Danesh A. , Henderson G. D.
Published: December 2007

The use of WAG (water-altemating-gas) injection can potentially lead to improved oil recovery from the fields. However, there is still an incomplete understanding of the pore-scale physics of the WAG processes and how these lead to improved oil recovery. Simulating the three-phase flow for prediction of the WAG performance in oil reservoirs is an extremely complex process. The existing three-phase relative permeabilities used in simulation are very approximate and do not properly account for the effects of fluid interfacial tension and rock wettability. Network model simulators are being developed to enable the prediction of three-phase relative permeability under different wettability conditions. However, such simulators need to be verified against experimental observations. In this paper, we present experimental results and discussion of a series of capillary-dominated WAG tests carried out in glass micromodels with wettability conditions ranging from water-wet to mixed-wet and oil-wet. Pore level fluid distribution and flow mechanisms were studied, and fluid saturation, at different stages of the experiments, were measured. The results showed that, under any of the wettability conditions, oil recovery by alternating injection of WAG was higher than water or gas injection alone. WAG recovery was observed to be higher for the oil-wet model than that in the mixed-wet one, which in turn was higher than that in the water-wet micromodel. Given enough time and more cycles of WAG injection, the recovery of the mixed-wet model seems to catch up with that of the oil-wet model.
Phase Behavior Studies of Two Model Surfactant Systems
Authors: Benton William J. , Natoli John , Qutubuddin Syed , Mukherjee Surajit , Miller Clarence A. , Fort Tomlinson
Published: December 2007

Phase behavior studies were carried out for two systems containing pure surfactants but exhibiting behavior similar to that of commercial petroleum sulfonates. One system contained the isomerically pure surfactant sodium-8-phenyl-n-hexadecyl-n-sulfonate (Texas 1). The other contained sodium dodecyl sulfate (SDS). Additional components used in both systems were various pure short-chain alcohols, NaCl brine and n-decane. Aqueous solutions containing surfactant, cosurfactant, and NaCl were studied over a wide range of compositions with polarizing and modulation contrast microscopy as well as the polarized light screening technique. Viscosity measurements were conducted on selected scans of the Texas 1 system. Maxima and minima of the scans were correlated with textural changes observed with microscopy. The aqueous solutions were contacted with equal volumes of n-decane, and phase behavior and interfacial tensions were determined. The middle microemulsion phase was found to be oil continuous close to the upper phase boundary and water continuous close to the lower phase boundary. Both the Texas 1 and SDS systems showed similar behavior in that the middle microemulsion phase was observed over the entire range of surfactant concentrations studied.
Phase Boundaries of Microemulsion Systems as a Way of Characterizing Hydrocarbon Mixtures
Authors: Shah Kishor D. , Green Don W. , Michnick Michael J. , Willhite G. Paul , Terry Ronald E.
Published: December 2007

Phase behavior of microemulsions composed of TRS 10-80, brine (10.6 mg/g NaCl), isopropyl alcohol, and mixtures of pure hydrocarbons was studied to determine the location of phase boundaries of the single-phase microemulsion region. Studies were conducted on pseudoternary phase diagrams where the pseudocomponents were isopropanol, brine, and a constant ratio of surfactant to hydrocarbon (S/H). Phase boundaries were determined by the titration method developed by Bowcott and Schulman,1 which was extended to systems of interest for oil recovery by Dominguez et al.2,3

The titration method involves the addition of brine to a single-phase microemulsion until phase separation occurs. Then the system is titrated to transparency by addition of isopropanol. Dominguez et al.2,3 demonstrated the applicability of the titration method for systems containing pure alkanes. They found upper and lower phase boundaries (high and low alcohol concentrations) for the microemulsion regions on S/H pseudoternary diagrams that were represented by linear relationships between the volume of alcohol and the volume of brine required to attain a single-phase microemulsion. This region, termed Region 4, bounded by linear phase boundaries, extends over a wide range of brine concentrations including regions of interest to enhanced oil-recovery processes.

The research reported in this paper extends the work of Dominguez et al.2,3 to mixtures of pure hydrocarbons. The locations of the lower phase boundaries for Region 4 were determined for four types of mixtures prepared with pure hydrocarbons ranging from C6 to C18.

In all phase behavior experiments, the lower phase boundary of Region 4 was a straight line when volume of alcohol was plotted against volume of brine. Furthermore, the slope of this phase boundary was found to be a linear function of alkane carbon number (ACN) for pure hydrocarbons and equivalent alkane carbon number (EACN) for mixtures of pure hydrocarbons.

The correlation of a property of the phase diagram (the slope of the lower phase boundary) with EACN suggests a new approach to characterization of hydrocarbon/surfactant systems. In our experience, the EACN determined from phase behavior studies is more reproducible than the EACN determined from methods involving measurements of interfacial tensions. This method has potential for characterization of surfactant/hydrocarbon systems for complex mixtures of hydrocarbons, including crude oils.
Toward an Accurate and Efficient Chemical Model for Hydrothermal Brines
Authors: Weare John H. , Harvie Charles E. , Møller-Weare Nancy
Published: December 2007

In this paper, we describe the development of a chemical equilibrium model for hydrothermal waters based on the semiempirical equations of aqueous electrolyte solutions recently introduced by Pitzer et al.1 We discuss application of this model to the system, Na/K/Ca/Mg/Cl/SO4/ H2O, at 25°C. Accurate solubility predictions (usually within 5 % of experimental results) can be made for ionic strengths of 0 to 20 m. Comparison with experimental data indicates that a theory parameterized by binary and ternary data can be used to predict solubilities accurately in much more complex mixtures. Mineral solubilities calculated with this model are compared with those calculated from models based on ion pairing. Whereas our predictions are typically within 5 %, the ion pairing models are substantially in error even at low ionic strengths.

We are extending our chemical equilibrium programs to include high temperature (T ≃ 200°C). We have assessed the availability of data for modeling hydrothermal waters. In this paper, we discuss the accuracy of existing high temperature data in terms of the binary HCl/H2O system. Our results indicate that below about 150°C, there may be a sufficiently accurate data base to parameterize a hydrothermal water model including all commonly occurring ions. Above 150°C, the data may not be reliable, and appropriate data should be collected for certain key systems.
Evaluation of the Low Tension Flood Process for High-Salinity Reservoirs—Laboratory Investigation Under Reservoir Conditions
Authors: Murtada Hani , Marx Claus
Published: December 2007

In northwest Germany, oil reservoirs are characterized by high-salinity brines with up to 23% TDS. For such salinity conditions, fatty alcohol derivatives with 4.5 ethene oxide (EO) units were found to lower the inter-facial tension (IFT) drastically and to mobilize residual oil almost completely.

Intensive flood experiments under reservoir conditions with the use of sandpacks 2 m in length allowed optimizing the low-tension process for an oil field that was considered a possible candidate. A combination of surfactant slug followed by a tailored mobility buffer showed best results in terms of additional oil recovery and process duration. A preflush of low-concentration aqueous polymer solution brought a decisive further increase in additional oil recovery.

Results obtained for the slug process indicated that variables such as IFT, surfactant concentration, flooding velocity, and pressure gradient influence the low-tension process in a combined manner.

Oil produced in the oil bank showed alteration in properties, compared with the oil used to saturate the pore space.
Characterization of Petroleum Sulfonates by a Nonaqueous Titration Method
Authors: Voss Kim R. , Bricker Clark E. , Michnick M. J. , Willhite G. P.
Published: December 2007

A new method is described for the determination of the equivalent weight for petroleum sulfonates. The method is based on the direct acidimetric titration of the sulfonate in acetic acid/acetic anhydride solvent using a titrant of perchloric acid in dioxane. From the titration, the moles of perchloric acid required to react with the sulfonate is measured. The equivalent weight is calculated from the grams of sample titrated and the moles of acid used. The potentiometric titration can be carried out in less than 10 minutes and can be done with 10 to 100 mg of sample.

The accuracy and precision of the procedure were examined by the titration of sodium salts of p-toluene sulfonate, 2-naphthalene sulfonate, and petroleum sulfonates. In general, values for the equivalent weight were within 2% of those values determined by the Epton titration, by wet ashing methods, or from the theoretical value. The relative standard deviation (RSD) for the procedure is estimated to be 0.5%. For p-toluene sulfonate, an RSD of 0.15% was calculated.

The new method was used to determine the equivalent weights for three fractions of a petroleum sulfonate obtained by the preferential elution from silica gel with alcohol. A series of samples with varying equivalent weight was prepared by proportional combination of the three fractions. Analysis by high-performance liquid chromatography (HPLC) gave a set of data points of peak areas for the series. A plot of equivalent weight as a function of disulfonate to total peak area ratio resulted in a straight line. The slope of this line is descriptive of the molecular weight range for the petroleum sulfonate.
Laboratory Evaluation of Prospective Enriched Gas-Drive Projects
Authors: Kehn D.M. , Pyndus G.T. , Gaskell M.H.
Published: December 2007

Introduction

Much attention has been given in the past few years to methods of increasing the recovery of oil from proven reserves. Numerous laboratories have made investigations to evaluate the possibilities of increased oil recovery by high-pressure injection of dry gas, injection of a propane slug followed by dry gas, solvent flooding, and by the injection at relatively low pressures of gases enriched with ethane and propane. Several years ago, Whorton and Kieschnick published the results of laboratory studies on high-pressure gas injection which showed that, in the case of light oils, recoveries could be considerably increased by sweeping the reservoir with dry gas at pressures in excess of 3,000 psig. The increase was attributed by those authors to the vaporization of oil at the invading gas front and viscosity and solubility effects produced at the front by the invading gas.

Later, Stone and Crump presented the results of a series of displacement experiments in which a light undersaturated crude oil was displaced from sand-packed columns with unusually high recoveries when the displacing gas was a rich condensate or a dry gas enriched with ethane or propane. They also conducted similar experiments at higher pressure on heavy undersaturated crude oil, although in this case the increase in recovery was not as great as in the case of the light oils. In both cases, viscosity reduction and swelling of the by-passed oil behind the invading gas front were believed to be responsible for the more favorable recovery of the original oil in place.

Within the past year, other investigators have presented the results of laboratory studies of miscible slug and solvent flooding recovery processes. This paper describes the laboratory methods developed for evaluating benefits to be obtained by enriched gas drive in specific reservoirs, and presents the results of several displacements of crude oils which possess a wide range of physical properties. The displacements were conducted at reservoir conditions of temperature and pressure.
Force Coefficients From Wave Project I and II Data Including Free Surface Effects
Authors: Dean Robert G. , Dalrymple Robert A. , Hudspeth Robert T.
Published: December 2007

Wave force data, obtained by Chevron Oil Field Research Co. in conjunction with Shell Development Co. and Exxon Production Research Co.. have been reanalyzed for drag and inertia coefficients. These data are the field results of Wave Projects I and II and consist of water surface elevations and forces on piles of various sizes at different elevations within the water column. The analysis here is based on the stream function wave theory and Morison's equation, resulting in drag (CD) and inertia (CM) coefficients including a dependency on Reynolds number. Principal findings are a somewhat higher value for CD at large Reynolds numbers than that obtained by Aagaard and Dean.1 Free surface effects include a run-up on the piling and an associated local modification in drag coefficients, resulting in reductions in overall forces and moments. Using a large data set of 349 waves (digitized at 0.1 second), variances between predicted and measured forces also were obtained that followed a normal probability distribution.
Borehole Position Uncertainty - Analysis of Measuring Methods and Derivation of Systematic Error Model
Authors: Wolff C.J.M. , de Wardt J.P.
Published: December 2007

This article presents a new model for describing well-position uncertainties. An analysis for surveying position uncertainties. An analysis for surveying errors is given that demonstrates that they are mainlysystematic rather than random. The error model, based on systematic errors, compares well withpractical experience. A graph is presented that shows practical experience. A graph is presented that shows typical lateral position uncertainties of deviated wellsfor various kinds of surveys.

Introduction

During the past 10 years, the uncertainties involvedin determining the true course of a borehole havebecome a cause for concern. The more deviated anddeeper the holes were drilled, the more often were theoperators faced with inexplicable differences betweenvarious surveys made in the same well. As early as 1971, Truex mentioned that possible lateral positionerrors of highly inclined wells could be up to 30 m ata depth of only 2000 m. Two years before that, Walstrom et al. introduced the ellipse-of-uncertainty concept to describe the positionuncertainty, which can be expected with various surveymethods. Experience, however, has shown that theellipse calculated by this random error model isunrealistically small, which is thought to be duemainly to the nature of the statistical error modelused.The essential differences between the existingrandom error model and the model proposed in thisarticle are illustrated by the following simplifiedexample. Consider the straight and inclined part of awell with these directional characteristics: total depthalong hole (AHD or DAH) 2500 m, surveyed at100 stations at 25-m intervals, and all having aninclination of I Delta I = 30 0.5 and an azimuthof A Delta A 90 1.The bottomhole position of this well in north, east, and vertical coordinates easily is found as

N = D AH sin I cos A = 0, E = D AH sin I sin A = 1250 m, andV = D AH cos I = 2165 m.

The position uncertainty of the bottom of thiswell, according to the error model presented in thisarticle, follows straightforwardly from theassumption that the measuring errors at all 100 stations havethe same magnitude (they are correlated fully).Hence, by simple trigonometry, as sketched in Fig. 1,

and

In the random error model, however, it is assumedthat the measuring errors vary randomly from onestation to another, which gives them a tendency tocompensate one another. This randomness of themeasuring errors causes the position uncertainty tobe smaller than the former values - in our example, by a factor equal to the square root of the number ofmeasuring stations, which is 100 = 10.

JPT

P. 2339
Rock Mechanics, Petrophysics, and Stratigraphy of the Tuscaloosa Trend
Authors: Traugott Martin O.
Published: December 2007

Tough drilling and evaluation problems fall to easy solutions in deep Tuscaloosa wells: Log resistivities in soft shales are linked to impending pore pressure reversals in deep sands; high-resistivity hard shales are linked to lost circulation intervals; and resistivity invasion profiles are linked to freshwater anomalies in boreholes with oil mud.

Introduction

Several onerous things can happen during the 150 or 180 days it takes to drill a deep Tuscaloosa well in south Louisiana. As an example, consider this scenario: A Tuscaloosa well penetrates the over pressured Chalk formation. The well kicks and subsequently loses returns. The operator sets protective casing and drills ahead into the Eagleford shale. Gas in the mud increases. He sets a liner, drills into the Massive Tuscaloosa, loses returns, and reduces mud weight. Drilling continues. The well penetrates the Interbedded Tuscaloosa and kicks hard. Pipe sticks. The well is sidetracked. Apparent pay zones are tested and flow fresh water. The depth is 18,000 ft (5500 m). The cost: $5 million. But things are not so tough if casing and evaluation programs are based on geomechanical and petrophysical concepts. Understanding this depends on understanding four basic ideas:Formations can be grouped into one of two classifications-soft or hard-based on resistivity logs.Soft (viscoelastic) shales often have high fracture gradients and high pore pressures depending on proximity to massive sands. (Pore pressures can be derived from resistivity logs.)Hard shales (and carbonates) often have lower pore pressures and lower fracture gradients depending on boundary conditions.Fresh water often occurs in isolated, lower-pressure sands, near high-pressure zones containing salt water.

Stratigraphy and Shale Resistivity

The Tuscaloosa wells penetrate several different stratigraphic units, some hard and some soft (Fig. 1). An outline is given here of the important intervals:

Het Lime

A hard carbonate and potential lost-circulation zone.

Claiborne Group

A soft shale interbedded with limes and sands. Not over-pressured except where the Wilcox sands are not developed.

Wilcox

A sand interbedded with hard, resistive shales. Not developed at the east edge of the trend.

Midway

A semisoft shale. Shale resistivity is 2 to 3 Omega typical depths, and fracture gradients are high based on breakdown tests.

Clayton

A thin, soft, over pressured shale. Pore pressures increase with depth as a function of distance from the lower Cretaceous shelf margin (Fig. 2).

Chalk

A thick carbonate that often is drilled underbalanced.

Eagleford

A thick, soft, often over pressured shale.

JPT

P. 428^
Hydraulic Fracture Geometry: Fracture Containment in Layered Formations
Authors: van Eekelen H. A. M.
Published: December 2007

One of the main problems in hydraulic fracturing technology is the prediction of fracture height. In particular, the question of what constitutes a barrier to vertical fracture propagation is crucial to the success of field operations.

An analysis of hydraulic fracture containment effects has been performed. The main conclusion is that in most cases the fracture will penetrate into the layers adjoining the pay zone, the depth of penetration being determined by the differences in stiffness and in horizontal in-situ stress between the pay zone and the adjoining layers. For the case of a stiffness contrast, an estimate of the penetration depth is given.
Buckling Behavior of Well Tubing: The Packer Effect
Authors: Mitchell R. F.
Published: December 2007

The equilibrium equations for a helically buckled tubing are developed and solved directly. The results show that the packer has a strong influence on the pitch of the helix, and that the pitch developed by the helix is different from the pitch calculated by conventional methods. In addition, the solution provides (1) shear loads and bending moments at the packer and (2) constraining force exerted on the tubing by the exterior casing. This last result can be used to estimate friction effects on tubing buckling.
Analysis of Pressure Buildup Data Following a Short Flow Period
Authors: Raghavan Rajagopal , Reynolds Albert C. , Meng Hai-Zui
Published: December 2007

Methods for analyzing buildup data following a short flow period are presented, discussed, and illustrated. A new type curve for uniform-flux and infinite-conductivity vertically fractured wells is presented. By matching buildup data with this new type presented. By matching buildup data with this new type curve, we can determine the dimensionless flowing time before shut-in. A method for converting buildup data to equivalent drawdown data is discussed. This method can be used to combine buildup and drawdown data to obtain a longer band of data for type-curve matching. This method canbe used for constant-rate production, constant-pressure production, and for the case where both pressure and rate production, and for the case where both pressure and rate vary during production.

Introduction

Over the past decade, the use of type-curve matching toanalyze pressure data has gained increasing acceptance. The advantages and dis advantages of type-curve matchingare well recognized and the procedure has become astandard tool to analyze data qualitatively, to identify flow regimes, and, quantitatively, to determine iformation parameters. Virtually all type curves available in the literature examine the pressure response at a flowing well-i.e., only drawdown solutions have been examined. These type curves may be used to analyze shut-in pressure behavior provided that the flowing time before shut-in is provided that the flowing time before shut-in is significantly longer than the maximum shut-in time. This limitation has prevented type-curve analysis ofpressure buildup data following short flow periods. pressure buildup data following short flow periods. The effect of a short flow period on pressure buildup data influenced by either wellbore storage or vertical fractures was presented recently. It was shown that significant errors result if proper care is not taken in analyzing pressure buildup data when the producing timeis short. Procedures to account for the influence of producing time were outlined. producing time were outlined. The objectives of this paper areto present anew correlation that considerably simplifies the use of buildup type curves for vertically-fractured wells givenin Ref. 1, andto suggest a procedure to analyze pressure buildup data by means of drawdown type pressure buildup data by means of drawdown type curves.

The procedures discussed here can be applied to single- or multiwell tests, to data obtained after shortor long flow periods, to constant or variable flow rates, and to virtually all wellbore conditions including data influenced by wellbore storage and skin and fracturesof finite or infinite conductivity.

Theory

The basic pressure buildup equation based on the principle of super position is given by principle of super position is given by (1)

Here, t is flowing time and Delta t is shut-in time. Thesymbols p and t denote dimension less wellbore pressure drop and dimension less time, respectively, and are defined as follows.

JPT

P. 904
Biopolymer Solution Viscosity Stabilization—Polymer Degradation and Antioxidant Use
Authors: Wellington Scott L.
Published: December 2007

Dilute solutions of polymers used to provide mobility control for EOR often lose viscosity, especially at higher temperatures. This loss of viscosity with time brings into question the feasibility of using polymers as mobility-control agents. A literature study of the many possible reaction mechanisms indicated that oxidation/reduction (redox) reactions involving free radicals probably caused polymer degradation and concomitant viscosity loss.

A preliminary search for antioxidants known to retard free-radical reactions located several types and positive synergistic formulations that significantly retarded biopolymer solution viscosity loss during accelerated tests at high temperature. The most effective type formulation found contained (1) a radical transfer agent; (2) a sacrificial, easily oxidizable alcohol; (3) a compatible oxygen scavenger; and (4) sufficient brine concentration. Samples prepared with this technology have not lost viscosity after 1-year storage at 207 °F [97 °C]. A high-surface-area effect (so-called "wall effect"), known to retard radical propagation, was also found to operate in the presence of sandpacks; this should be beneficial in porous media. The variables and beneficial antioxidant formulations identified in this study allow tentative conclusions and recommendations regarding biopolymer mixing and handling procedures prior to injection.
The Effects of Mechanical Degradation and Viscoelastic Behavior on Injectivity of Polyacrylamide Solutions
Authors: Seright R. S.
Published: December 2007

Results of recent experiments that clarify the effects of mechanical degradation and viscoelastic behavior on the flow of partially hydrolyzed polyacrylamide solutions through porous media are presented. From these results, a simple model that may be used to predict injectivity of polyacrylamide solutions is developed.

Injection pressures for linear corefloods are shown to be separable into two components: (1) an initial pressure drop associated with the entrance of polymer into the sandstone and (2) a constant pressure gradient throughout the remainder of the core. Entrance pressure drop is zero until the polymer solution flux increases to the rate where mechanical degradation takes place. Thereafter, entrance pressure drop and the degree of polymer mechanical degradation increase with increasing flux. In addition, polymer solutions that undergo a large entrance pressure drop and a high degree of mechanical degradation when first injected into a core show no entrance pressure drop and no further degradation after reinjection into the same core at the same flux. These observations suggest that the entrance pressure drop is associated closely with the process of polymer mechanical degradation.

A new correlation is developed that may be used to determine entrance pressure drop and the level of mechanical degradation directly as a function of sand-face flux, permeability, and porosity. This correlation is more convenient to apply and less dependent on flow geometry than previous correlations.

Based on these observations, a model is developed that may be used to estimate injectivity of polyacrylamide solutions in linear or radial flow geometries. This model takes into account the entrance pressure drop and the dilatant nature of the polymer near the wellbore. Predictions made with this model are compared with experimental results.
Polymer Flooding in North Sea Reservoirs
Authors: Davison Paul , Mentzer Eric
Published: December 2007

The use of polymer solutions to enhance oil-displacement efficiency by seawater injection in North Sea oil reservoirs has been investigated. We have evaluated over 140 polymers for viscosity retention and porous media flow performance under high temperature (90°C), high salinity, and high pressure. Scleroglucan polymers give the best performance in our tests. Polyacrylamides (PAAm's) are particularly unsuitable for mobility control. Using polymers to enhance seawater injection and waterflooding processes is not practical in North Sea reservoirs, but selective injection may improve local sweep efficiencies.
The Influence of Vertical Fractures Intercepting Active and Observation Wells on Interference Tests
Authors: Mousli Naelah A. , Raghavan Rajagopal , Cinco-Ley Heber , Samaniego-V. Fernando
Published: December 2007

This paper reviews pressure behavior at an observation well intercepted by a vertical fracture. The active well was assumed either unfractured or intercepted by a fracture parallel to the fracture at the observation well. We show that a vertical fracture at the observation well has a significant influence on the pressure response at that well, and therefore wellbore conditions at the observation well must be considered. New type curves presented can be used to determine the compass orientation of the fracture plane at the observation well.

Conditions are delineated under which the fracture at the observation well may influence an interference test. This information should be useful in designing and analyzing tests. The pressure response curve at the observation well has no characteristic features that will reveal the existence of a fracture. The existence of the fracture would have to be known a priori or from independent measurements such as single-well tests.
The Topology of Phase Boundaries for Oil/Brine/Surfactant Systems and Its Relationship to Oil Recovery
Authors: Bourrel M. , Chambu C. , Schechter R. S. , Wade W. H.
Published: December 2007

Surfactant/oil/water phase diagrams have become the most important screening tool used to select microemulsion systems for enhanced oil recovery. The number of phases coexisting at a given salinity, the extent of the single-phase region, and the position of the phase boundaries all have relevance with respect to oil displacement efficiency.

It is shown that the phase diagrams can be made to take on different configurations depending on the alcohol cosurfactant, the salinity, the impurities present in the surfactant, and the dispersity of the surfactant mixture.

Besides the importance of the phase boundary shape, this study provides further insight into factors determining the height of the binodal surface on the pseudoternary phase diagram. Results show the effect of salinity as well as the surfactant, alcohol, and hydrocarbon types on the height of the binodal surface. It is shown that salinity is the main factor; other parameters have little or no influence once a surfactant has been selected.

Finally the microemulsion viscosity is shown to be related to the proximity of the formulation to phase boundaries. Extensive data for one system are presented.
Acidizing Sandstone Formations With Fluoboric Acid
Authors: Kunze Kenneth R. , Shaughnessy Chris M.
Published: December 2007

The continuing search for an effective deep-penetrating sandstone acidizing system recently has focused on fluoboric acid (HBF4). Because this acid first must hydrolyze in water to produce HF, it was believed that deeper radial penetration of live acid could be achieved during matrix acidizing operations. However, a thorough experimental study has shown that typical formation temperatures will cause fluoboric acid to spend at a rapid rate similar to that of conventional hydrofluoric acid (HF), thereby severely limiting its usefulness in most sandstone formations. Furthermore, the same silica reprecipitation potential associated with HF acidizing is also inherent in the HBF4 system.
Physics of Oil Entrapment in Water-Wet Rock
Authors: Mohanty K. K. , Davis H. T. , Scriven L. E.
Published: December 2007

Displacement of oil from an initially oil-filled porous rock by water consists of advancement of menisci and rupture of oil connections. In displacements controlled by capillarity, which are typical of oil reservoir floods, these pore-level events are governed by the local pore geometry, pore topology, and fluid properties, but the pressure field initiates these pore-level events and integrates them with the externally imposed Darcy flow.

This paper reports the physics of the pore-level events and their integration on a computationally simple model of rock: a square network of pores. The novelty of the approach lies in keeping track of the evolution of the displacement front and in constructing an approximation of the entire pressure field that carries the information essential for predicting the evolution.

The result gives insight into the state of the residual oil saturation and its dependence on pore geometry and the capillary number, Nca, of displacement. As the capillary number increases, the residual oil saturation decreases and the residual oil blobs tend to be smaller. As the pore size distribution becomes wider, the decrease of residual oil saturation with capillary number becomes smoother.
Steady-State Measurements of Relative Permeability for Polymer/Oil Systems
Authors: Schneider F. N. , Owens W. W.
Published: December 2007

Means for increasing tertiary oil recoveries from previously waterflooded viscous oil reservoirs are receiving added attention today as a result of industrywide efforts to improve U.S. oil producing rates and reserves. Injection of a bank of polymer solution that precedes injection of a miscible slug (e.g., a micellar fluid) can reduce reservoir permeability contrasts and result in improvement of the sweep efficiency of the process. To evaluate the potential magnitude of improved recovery and economics of prior polymer slug injection, there is a need for basic polymer/oil relative permeability data for use in performance evaluation calculations. Such relative permeability data were measured by steady-state procedures on a suite of 18 outcrop and formation core samples ranging in permeability from about 50 to 1,200 md. Six different Polyacrylamide polymers were tested, and resistance and residual resistance data were obtained on each. Data were obtained in both oil-wet and water-wet systems. The observation in these studies was that the presence of polymers in the water phase had a significant and consistent effect, lowering water relative permeability over the entire water saturation range. In many of the tests, the presence of flowing polymer or its residual effect during subsequent brine flow had no effect on oil relative permeability. In several tests, polymer contact actually improved oil mobility through increases in oil relative permeability at all levels of oil saturation. Permeability level and polymer type produced no clear-cut differences in flow behavior. The obvious differences in core wettability resulted in widely varying relative permeability characteristics, but again the effect of polymer contact was about the same, qualitatively, as obtained on the water-wet cores.
Unique Enhanced Oil and Gas Recovery for Very High-Pressure Wilcox Sands Uses Cryogenic Nitrogen and Methane Mixture
Authors: Eckles Wesley W. , Prihoda Clarence , Holden W.W.
Published: December 2007

Primary recovery is low for the volatile oil and retrograde condensate reservoirs in the hot, high-pressured, multilayered Wilcox sands in the Fordoche field, Point Coupee Parish, LA. Recovery from oil reservoirs by depletion is predicted by numerous model studies to be 26 to 36% of the OOIP. Condensate recovery by depletion is predicted to be 19% of the original condensate in place and 25% of original separator gas in place. The injection of dry natural gas at high pressures will result in a miscible displacement of reservoir fluids. The immiscible displacement of reservoir fluids. The injection of a mixture of nitrogen and dry gas is predicted to be as effective as injecting dry natural gas. Model studies of gas injection in volatile oil reservoirs predict recoveries from 47 to 54% of the OOIP, and in the retrograde condensate reservoir recoveries are predicted to be 30 and 46% of the original condensate and gas in place. Oil recovery studies at 6,955 psig indicate that gas injection will displace 89% at breakthrough and 93% at blowdown at 100% sweep efficiency. A well stimulation program has been developed that results in a 2.5-fold increase in production rates.

Introduction

The Fordoche field was discovered by Sun Oil Co. in 1966. The location is shown in Fig. 1. The field was developed fully on 160-acre well spacing by 1970. A total of 36 wells was drilled during the short 4-year development period. Well depths ranged from 11,800 to 16,500 ft (See Fig. 2, a typical log for the Fordoche field.) Seven reservoirs encountered between depths of 11,300 to 13,900 ft had initial bottomhole pressures (BHP's) ranging from 8,372 to 11,018 psig and bottomhole temperatures (BHT's) ranging from 226 to 278°F. The Sparta sands are undersaturated oil reservoirs. The Wilcox 4 and 5 (W-4 and W-5) sands are gas-condensate reservoirs. The W-8, W-12, and W-15 sands are undersaturated volatile oil reservoirs. All of the Wilcox reservoirs experienced rapid rates of reservoir pressure depletion. Productivity of all wells declined severely.

After evaluating water injection and gas injection programs, high-pressure gas injection was selected for the two major oil reservoirs, W-8A and W-12A, and for the largest retrograde reservoir, W-5A. (See Figs. 3, 4, and 5).

A very high-pressure miscible gas injection project was instituted to maintain pressure and well productivity and to enhance ultimate recovery. Initially, extraneous gas was purchased for makeup and injected with the processed natural gas produced in the field. Because of the increasing cost of natural gas and the restricted oil price of $5.35 per barrel, economics dictated that the project be changed to a partial pressure maintenance program with a lower ultimate recovery or find a substitute for natural as used for makeup.
"Silicalock" - A Novel Sand-Control Process for Gas Wells
Authors: Davies David R. , Zwolle Simon , Meijs Frans H.
Published: December 2007

A novel sand-consolidation technique especially suited for the prevention of sand influx in gas wells is described. This technique-"Silicalock"-has the advantage of being a single-chemical one-phase dynamic treatment that can be carried out through tubing and that leads to reduced chances of productivity impairment. The results of three successful field tests also are described.

Introduction

The importance of natural gas as an essential and clean source of energy has increased considerably in recent years. Much of this gas is produced from loosely consolidated sandstone reservoir that require some form of sand control. Experience in both field and laboratory has shown that the probability of sand influx increases as a reservoir is depleted and pore pressure decreases. Production facilities may be, designed to cope safely with the production of small amounts of sand. However, sand production over a long time is generally not acceptable since it often leads to serious erosion problems. Furthermore, some of the produced sand will normally remain in the wellbore, which may result in a sand fill that adversely affects the well's productivity. The standard forms of sand control, primarily developed for oil wells, also may be applied to gas wells. These include(1) beaning back production, (2) mechanical methods such as wire-wrapped screens with and without gravel packs, and (3) consolidation processes in which the sand grains are "glued" together. However, none of these methods makes allowance for the special conditions found in gas wells, and they are therefore not optimal. The Shell group of companies has been exploiting several large gas fields during the past decade, including the giant Groningen field [operated by the Nederlandse Aardolie Mij. (NAM)] where about 280 wells can produce up to 480 × 10 std m /d during peak winter production periods. A view to possible future sand problems justified the star, of development of a sand control process especially geared to the conditions prevailing in gas wells. This has resulted in the novel chemical technique "silicalock" described in this paper. The process is based on the following reaction.

SiCl4 + - 2H20- silica cement +4 HCl.

The water is supplied by the connate water naturally adhering to the sand grains. The process differs from previous sand consolidation processes involving silicon tetrachloride in that it operates from the gas phase. The "silicalock" technique consists in vaporizing liquid silicon tetrachloride into a stream of high-pressure nitrogen gas. The mixture is injected into the well, preferably through coiled tubing. Immobile water present in the near-wellbore region is converted into silica cement, which cements the grains together, thus preventing any (further) influx of sand into the well.

JPT

P. 2087^
Field Experience Utilizing High-Density Brines as Completion Fluids
Authors: Spies R.J. , Himmatramka A.K. , Smith J.R. , Thomas D.C.
Published: December 2007

This paper presents the results of 2- years experience using high-density brines as completion fluids in fields offshore Texas. This experience has resulted in a number of improvements in field methods of handling and using these fluids in making gravel-packed completions in abnormally pressured wells. Because the required fluid densities have been in the range of 15.0 to 15.6 Ibm/gal (1797 to 1869 kg/m ) and the fluids have cost several hundred dollars per barrel, the cost of lost or contaminated fluid has been a significant factor in carrying out these completions. We have developed our current completion methods in an effort to minimize fluid costs, maintain well control, maximize productivity, and minimize rig time per completion. The methods developed include those for perforation cleaning, gravel packing, solids removal, density control, control of fluid losses, and prevention of crystallization. The results of these methods generally have been successful in controlling completion costs and apparently are successful in providing good sand control and adequate flow efficiencies on the basis of initial test results for about two-thirds of the wells.

Introduction

Amoco Production Co., as operator for a group consisting of Mobil Oil Corp., Union Oil Co. of California, and Amoco, acquired three adjoining Outer Continental Shelf leases in the May 1974 federal offshore lease sale in what would become the High Island Block A-537 field, The field has been the primary location where we have used high-density brines. This paper describes the basis for using heavy brines in these completions, the plans developed for the completions, our experience in performing them, the resultant evolution of our procedures, and the achieved well productivities, which have confirmed the advantage of using a solids-free completion fluid.

The field is located approximately 85 miles (137 km) south-southeast of Galveston, TX, in water depths of 190 to 200 ft (58 to 61 m) in the Gulf of Mexico. Exploratory drilling began in 1974, and a total of five exploratory wells were drilled during 1974–75. The first exploratory well drilled in the field, OCSG-2698 Well No. 1, encountered hydrocarbons in Pleistocene sands while being drilled with 16.5 lbm/gal (1977 kg/m3) mud. The well was cased, and a drillstem test (DST) was made in a 10-ft (3.05-m) perforated interval. The well flowed at rates of 450 to 720 B/D (71.5 to 114 m3/d) oil. The shut-in bottomhole pressure (BHP) was 5.243 psig (36.1 MPa) [a 13.7-lbm/gal (1641 -kg/m3) equivalent] at 7,352 ft (2241 m) TVD. Following this DST, sand had to be washed from the well beginning at a depth 80 ft (24.4 m) above the perforated interval, indicating that sand control would be necessary in wells completed in this field.

JPT

P. 881^
The Radial Movement of Permeability Fronts and Multiple Reaction Zones in Porous Media
Authors: Hekim Yusuf , Fogler H. Scott , McCune Conwell C.
Published: December 2007

Sandstone formations contain a variety of minerals including carbonates, clays, feldspars, quartz, and, in some cases, valuable compounds of uranium, vanadium, and copper. When a reactive fluid such as acid is injected into these porous rocks to dissolve the minerals, their dissolution rates are different because of differences in structure and chemical composition. Consequently, multiple reaction zones develop as a reactive fluid flows through the rock. This study, describing the movement of these reaction zones during sandstone matrix acidizing, also has application in hydrometallurgy and in-situ acid leaching of minerals.

Laboratory tests to predict the effects of acid injection usually are carried out by flowing acid through a core sample while permeability and fluid effluent concentration are monitored. If the minerals in a particular sample dissolve at approximately the same rate, a lumped parameter model satisfactorily describes the movement of a single reaction zone through the core. However, for the case of high temperatures, long cores, or long injection times, this model does not predict the effluent acid concentration correctly, and a distributed parameter model including the movement of multiple reaction zones is required. This paper describes the development of such a model and its verification by core flow experiments.

The study shows that when various minerals including quartz are being dissolved during matrix acidizing, larger acid volumes are required than predicted by previous models.
Two Decades of Electrical Logging
Authors: Doll H.G.
Published: December 2007

The present paper, written at the request of the editor of the JOURNAL OFPETROLEUM TECHNOLOGY, gives a brief history of the various logging methods andof their progressive development during the last 20 years. More generally, itrefers to the different operations performed in drill holes at the end of anelectric cable to locate the permeable formations and to determine theircharacteristics, such as porosity, fluid content, and dip; to procure samplesof the formation by sidewall coring; and to determine data concerning the drillhole itself, as, for example, its diameter and deviation from vertical.

Electrical Logging

Correlation and Bed Thickness Determination

The first log in an oil well was made in 1927 and comprised only aresistivity curve. The sharp contrast in resistivity from one bed to anothersuggested that such a log would be very useful for correlation between wells, aconclusion that was confirmed by field experience. In 1931, the SP log wasadded. This parameter not only improved the qualities of the electric log forcorrelation purposes, but made it possible, in many cases, and particularly insoft formations, to locate permeable beds and to determine their boundarieswith reasonable accuracy. The combination log, comprising one resistivitycurve, generally a short normal, and the SP log, was introduced commercially inthe United States in 1932 and was immediately recognized as a very valuabletool.

First Attempts at Quantitative Analysis

Until about 1937, the application of electrical logging was, in many cases, limited to correlation and bed thickness determination. During that period, however, attempts were progressively made to detect oil sands by qualitativeinterpretation, especially by comparing the resistivity of a given permeablebed in different wells drilled in the same field. This resulted in valuableconclusions in many cases, and also brought to light the important influencethat mud filtrate invasion has on the apparent resistivities as measured in thedrill hole.

Around 1938 the problem of quantitative interpretation received increasedattention, when the first paper dealing with that problem was published. Fromthere on, not only the service companies, but the oil companies themselves, didextensive work to improve the interpretation. Subsequent papers discussingempirical relations between formation factor and porosity, and betweenresistivity of the uncontaminated part of a permeable bed and its oil and watersaturation, brought important and basic contributions to the problem ofquantitative analysis.
How Policies Affect Rates of Recovery From Mineral Sources
Authors: Lohrenz John , Burzlaff Bernard H. , Dougherty Elmer L.
Published: December 2007

Higher royalty and other production-contingent payment policies cause some otherwise economical mineral projects to become uneconomical. But, even for projects that are still economical, such payments lead to a slower rate of mineral production and may decrease ultimate recovery.