bluuebunny/crossref_metadata_2025_split huggingface dataset:
Determination of Residual Oil Saturation After Waterflooding
Authors: Cordiner F.S. , Gordon D.T. , Jargon J.R. 
Published: December 2007

Abstract
This paper illustrates the use of several independent testing and calculational procedures for determining residual hydrocarbon saturations remaining in a reservoir after waterflooding. These methods consist of material balance calculations, analysis of well test data, pressure transient testing, core analyses, and pressure transient testing, core analyses, and borehole log calculations.
Results of this work indicate: Good agreement was obtained between the several independent methods. Pressure transient testing is a valuable tool for measuring in-situ formation properties such as effective permeability to water and total compressibility. Values of compressibility obtained indicate gas saturation remaining after waterflooding is essentially zero. Water-oil relative permeability data is an important part of the analysis technique. Laboratory derived data should be carefully examined for validity. Field cases show that waterflood performance tends to verify laboratory kw/ko data as well as indicate residual oil saturation. Careful analysis of borehole logs can be very helpful. One of the field cases verifies the existence of saturation gradients, A comprehensive approach, utilizing all available tools, provided satisfactory and meaningful results provided satisfactory and meaningful results in both field cases reported.

Introduction
Depletion of domestic oil reserves in the face of increasing demands for energy has spurred development of new or improved techniques by which additional oil may be recovered from known reservoirs. Many of these reservoirs have already been depleted by waterflooding or by other secondary recovery methods. Whether tertiary recovery attempts are justified depends largely on a careful evaluation of the residual oil remaining in the reservoir.
Most of the oil which is potentially recoverable by tertiary recovery processes is found in old fields where data are either scarce or are of poor quality. Types of data generally available are as follows:
1. Oil production history, usually on lease or farm basis.
2. Produced water-oil ratio and gas-oil ratio histories.
Simple But Accurate Equations to Evaluate Wellbore Pressure Drawdown for Horizontal and Vertical Wells
Authors: Ouyang Liang-Biao , Thomas L. Kent , Evans Clayton E. , Aziz Khalid 
Published: December 2007

Abstract
A novel procedure is proposed for a quick and accurate evaluation of bottomhole wellbore pressure. The procedure has led to simple correlations for both horizontal and vertical wells which can be applied to calculate the bottomhole wellbore pressure and productivity index for the entire producing period. The correlations proposed here provide an excellent approximation of the semi-analytical solution at a much reduced computational time. Successful validation of the equations for different well locations and different reservoir geometries has also been achieved.

Approach
Bottomhole wellbore pressure and productivity index are two important quantities for both horizontal and vertical wells. For a horizontal or vertical well in a homogeneous but anisotropic reservoir, analytical equations can be obtained for bottomhole wellbore pressure drawdown once pseudo-steady state is reached. Practically, simple equations to evaluate the bottomhole wellbore pressure drawdown in early and transient time are as important as those for late time when the pseudo-steady state flow occurs. Although either the integral transformations (IT) (such as Laplace and Fourier) and separation of variables (SOV) method or the instantaneous point source/sink superposition and the Newman's product method may be used to determine the wellbore pressure drawdown, they take nontrivial (and usually long) computational time to get results, as a consequence they are impractical for routine reservoir engineering applications, such as well performance modeling. Therefore, a novel procedure is proposed here to develop simple yet accurate correlations to evaluate bottomhole wellbore pressure and well productivity index. The idea is very simple and the procedure consists of the following three steps:
Step 1. Use the instantaneous point source/sink solution (IPSS) approach to compute wellbore pressure drawdown at different times;
Step 2. Design appropriate functional forms which reflect characteristics of the wellbore pressure variation with time;
Step 3. Apply a nonlinear regression method to determine the relevant correlation coefficients.

Results
Correlations for Horizontal Wells. Two functional forms of the wellbore pressure drawdown of horizontal wells, which are valid for the entire time period (from early time to transient and then to late-time long after pseudo-steady state is reached) have been tried for correlating the wellbore pressure drawdown data for different horizontal wells:
Form I:
(1)
Form II:
(2)
where
(3)
The values of correlation coefficients, a, b, A and B, for different horizontal wellbore lengths, well locations and reservoir dimension ratios are given in Ref. 2. It was found that both functional forms can provide accurate predictions of the wellbore pressure for the entire time range.
P. 287^
Two-Bank Miscible Tertiary Oil Recovery Process
Authors: Ayers Robert C. 
Published: December 2007

Abstract
Results of a laboratory investigation of a two-bank, water-driven, miscible tertiary oil recovery process indicate that substantial quantities of additional oil can be obtained from flooded out reservoirs under favorable conditions.
This process uses an initial bank of tertiary amyl alcohol followed by a second bank composed of sodium xylene sulfonate, methanol, a thickener, and water. These two banks can be driven through a reservoir by a large, thickened water bank driven, in turn, by formation water.
Although technically feasible the process does not appear economically process does not appear economically attractive at this time.

Introduction
Development of a solvent bank which will yield a miscible displacement of oil by water is of considerable interest to the oil industry since it can provide a combination of the benefits of the high displacement efficiency of miscible processes with the favorable injection characteristics of water. Water is cheap and readily available in most locations, and the technology for its injection is well developed. Consequently, methods for improving its displacement efficiency are highly desirable.
Two-bank miscible processes are based on the thesis that more favorable phase behavior can be achieved using two banks of solvent rather than one. Fig. 1 illustrates a typical process in which a preferentially oil-soluble solvent slug miscibly displaces oil and immiscibly displaces water. This bank is driven by a bank of a preferentially water-soluble solvent which in turn is driven by water. In each case a miscible displacement is achieved.
In the subject process, the first bank is composed of an oil miscible alcohol and the second of a mixture of methanol and an aqueous solution of a low molecular weight aromatic sulfonate. This system offers improved miscibility and mobility characteristics over previously studied two-bank processes.
Modeling of Non-Darcy Flow Through Porous Media
Authors: Thauvin F. , Mohanty K.K. 
Published: December 2007

Abstract
Darcy's law is inadequate for describing high-velocity gas flow in porous media, which occurs in the near wellbore region of high capacity gas and condensate reservoirs. This study is directed at understanding the non-Darcy flow behavior. The Forchheimer equation,
(1)
describes the relation between pressure gradient and velocity where × represents the distance, p the pressure, v the velocity, the fluid density and the fluid viscosity, K the permeability and the non-Darcy coefficient of the porous medium. A pore-level model has been developed to describe high velocity flow and test the validity of Forchheimer equation. The inputs to the model are pore size distributions and network coordination numbers. The base case input parameters are listed in Table 1. The outputs are permeability (K), non-Darcy coefficient (), tortuousity () and porosity (). The size of the cubic network used in our computations does not influence the results if larger than 15x15x15. Typical calculations are done on 20×20×20 networks.
The non-Darcy term has been found to be proportional to the square of the velocity as presented in the Forchheimer equation. This term arises due to inertial effects in pore contractions, expansions and bends. The typical contributions of these terms are listed in Table 2. Turbulent effects contribute at very high velocity, not typical of near-wellbore flow
Permeability, non-Darcy coefficient, tortuousity and porosity depend on the morphological characteristics of the system, as shown in Table 3. As the average throat radius increases the non-Darcy coefficient decreases sharply, the permeability increases, the porosity increases slightly and the tortuousity decreases slightly. Any change in the average body radius has no significant impact on the permeability and the tortuousity. The porosity increases with the increase in body radii and the non-Darcy coefficient increases slightly. As the average coordination number decreases, the non-Darcy coefficient increases sharply, the permeability decreases, the porosity decreases slightly and the tortuousity increases. Finally, as pores shrink, (either due to increase in compaction factor, a or deposition thickness, b), the non-Darcy coefficient increases, the permeability decreases, the porosity decreases and the tortuousity does not change significantly. For each morphological change, a correlation between the non-Darcy coefficient and the other flow parameters has been established. The approximate correlations between the non-Darcy coefficient and the other flow parameters have been established which fit data from different morphological variations, as shown in Table 4. These correlations perform better than the correlations from the literature. They need to be tested against experimental data.
P. 313^
Management of Formation Damage by Improved Mud Design
Authors: Azizi T. , Jin W. , Rahman S. S. 
Published: December 2007

Abstract
Minimising filtrate loss into the formation by forming a filter cake with low porosity and permeability near the wellbore region is the key to managing formation damage problem. Visualising and understanding the structure of a filter cake can help formulate a drilling fluid system that provide an effective caking process with reduced water loss.
In this study, a technique that identifies the appropriate mud caking process is suggested. It can be applicable to relevant sandstone formations within 2 inches from the wellbore. This identification technique is based on the measurement of filtrate loss, the measurement of the return permeability of cores exposed to selected muds and the visual observation on the micro-level of cake structures of these muds in order to describe them and highlight their merits. A good mud system is the one which have a low filtrate loss, a low return permeability and a filter cake structure close to that of the ideal internal and external filter cake. This study also provides an investigative and comparative look at the internal and external filter cake structures of different muds using the Scanning Electron Microscopy.
This technique verified that the glycol and petrofree drilling fluids possess the characteristics and filtration properties of good mud systems. The glycol filter cake structure was superior to those of the solid free /low solid KCl-polymer muds. Scanning Electron Microscopy provided clear and descriptive images of the structures of internal and external filter cakes.
The Prediction and Avoidance of Formation Damage Induced by Scale Inhibitor Squeeze Treatments
Authors: Bunney J. R. , Jordan M. M. , Sorbie K. S. 
Published: December 2007

Abstract
Scale inhibitors are routinely injected into the near wellbore formation in "squeeze" treatments in order to prevent the buildup of mineral scale. The inhibitor must then interact with the formation such that it is retained and returns over a suitably long period of time (3–18 months) at a concentration above the threshold level, Ct. However, the introduction of a high concentration (2.5 to 20% solution) scale inhibitor slug, which is usually of low pH (2 to 4.5), along with the associated seawater overflush into the near well-bore region has the potential to cause formation damage. This damage may result from the dissolution of authigenic cements (carbonate and clay) which may lead to sand production, fines migration and the precipitation of iron carbonates and oxy-hydroxide gels. In order to minimise this risk and to correctly select both chemicals and operational strategy, the interaction between injection fluids, formation minerals and pore fluids must be adequately understood.
The main objective of this paper is to investigate how geochemical modelling can help us to analyse and predict the consequences of applying low pH inhibitor packages in field core of known mineralogy. This field example is chosen from a large database of reservoir condition corefloods which has been assembled at this laboratory. The modelling results for pack floods using the mineral separates (calcite and K-feldspar) are first presented before describing the results for the core flood. It has been found that the geochemical model cannot be applied without some careful consideration of the gross kinetics of certain thermodynamically favourable reactions. For example, dolomite is predicted when magnesium ions are present in the flooding brine and calcite is contained in the core. In practice, however, this is not observed and the reaction must be suppressed when considering production time scales. In addition, the effects of the inhibitor, which is itself a weak polybasic acid (H10A in the case of DETPMP), must be taken into account. Here, this is dealt with empirically since the entire range of pKa values and calcium binding constants for the inhibitor were not known. A number of preliminary conclusions are presented on the utility and applicability of geochemical modelling to inhibitor package/rock interactions.
Evaluation of Frac and Pack Completions and Future Outlook
Authors: Ayoub J. A. , Barree R. D. , Chu W. C. 
Published: December 2007

Abstract
Frac and Pack introduced in the early 90'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 screenout1" 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 non fractured 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.
Productivity Effects of Drawdown and Depletion in Open Hole Completions: Do Screens Plug?
Authors: Tronvoll J. , Sønstebø E. F. 
Published: December 2007

Abstract
Physical model experiments of sand production and productivity change in open hole, single screen completions have been performed. Synthetic and outcrop sandstone samples containing a drilled vertical scaled borehole with a concentric single screen in place were tested under conditions of realistic formation stresses and radial fluid flow. The increase of the drawdown and depletion, by raising the effective external stresses and the pore pressure gradient, to conditions by far exceeding the formation collapse stress, resulted in productivity reductions. The differential fluid pressure over the screen did, however, never exceed 10 kPa; which is negligible compared to the near-wellbore formation pressure drop. The variation of the screen-formation annular clearance and the mismatch of the screen slot opening to the formation grain size distribution did not alter the productivity significantly. However, transient sand production through the screen occured when the screen slot opening was oversized. The productivity was, however, reduced when the screen-formation annulus was gravel-packed.
Understanding Foam Flow Physics: The Role of Permeability
Authors: Veeningen Daan , Zitha Pacelli L. J. , van Kruijsdijk Cor P. J. W. 
Published: December 2007

Abstract
We develop a model for the determination of gas and water relative permeabilities from pore size distribution functions. The model originates from percolation ideas, and considers two situations: (a) gas and liquid without surfactant, and (b) gas and liquid with a surfactant.
In the first case, we show that the relative permeabilities are coherent with those obtained in past studies. This proves the consistency of our model.
In the second case, the surfactant leads to the dispersion of gas in the liquid phase (foam). We determine the ensuing partitioning of mobile and immobile gas. Then we show that foam relative permeability increases with the permeability. We argue that the decline of foam mobility with increasing permeability is probably due to dominant increase of foam effective viscosity. However, at the present stage, the model could not confirm the dependence of foam mobility on a (−1/2) power of the permeability.
Matrix Treatment in Horizontal Openhole Wells: Design of Viscous Diverter Slugs and Treatment Fluid Placement Optimization
Authors: LIETARD Olivier 
Published: December 2007

Abstract
Matrix treatments of openhole horizontal wells are extremely difficult. Placement of the treatment fluids at the very places where necessary, i.e. where damage exists, calls for diversion techniques of superior performance, due to the length of the section to be treated. Failure in achieving high diverting efficiency results in either incomplete damage removal and/or requirements for uneconomical volumes of treatment fluids.
Suspensions of particulate diverting agents build up very efficient cakes, however are costly due to the huge depositing surface. Therefore, the preferred diverting technique consists in pumping viscous banks into sections of high fluid intake. These banks are made of either non-Newtonian gels or foams having downhole qualities in the 60 to 85% range.
The aim of the present paper is to provide modeling equations for the radial placement of viscous pills around openhole horizontal wells. Primary porosity reservoir rocks are considered (usually 50- to 5,000-mD permeability sandstones) as well as naturally fractured ones (mostly carbonates). The pills are made of gels of Power-law fluid mechanics behavior. The increasing apparent viscosity of the gel with increasing distance to the well (due to decreasing shear rate) is taken into account.
Fluid bank pseudoskin equations are derived and used to optimize the diverting process. Optimization is either achieved by the selection of the proper characteristics of the viscous pill (e.g. n’ and K’ coefficients of a Power-law fluid) or by the pill volume and injection rate at which the latter is squeezed into the reservoir rock. Quantitative guidelines are provided with the aim of minimizing the cost of the diverting process as well as the duration of the matrix treatment.
Vertical Integration as a Basis for the Best Utilization of Gas and Condensate from a Field
Authors: Barone Nino , Blanco Eduardo , Alvarado Ruben 
Published: December 2007

Abstract
The Ramos field in the Argentine Northwest Basin constitutes the largest gas reserve throughout its extension, the country's second proved reserve, and it has the well with the largest single production in the Southern extreme of South America. The formation of Pluspetrol Energy S.A. as a company having power generation as its main purpose and aimed at the best utilization of the available product, is concentrated on the vertical integration of production, transportation, and thermoelectric generation through the use of natural gas as raw material.
Such integration starting in the production area, projects for its final stage the setting up of a power plant in El Bracho, Province of Tucuman, some 600 km away from the production field.
The power plant site has been chosen based on the availability of power transportation capacity with access to the large consumption areas. Diverse alternatives have been analyzed across Campo Duran-Buenos Aires gas pipe and the production area itself has also been considered as a possible location. The power generation process, initiated with the installation of an open cycle of 152 MW will he expanded to 304 MW with the addition of the second gas turbine generator. In the final stage, with the conversion to combined cycle, the gross power output will reach 460 MW.
In the national sphere, there have been cases in which gas production and power generation have been integrated in the production area itself while the experience described constitutes the first attempt in which the producer has assumed field development, allowing for transportation increase, -in this case at the expense of third-parties-, and creating the consumption market through the setting up of a power plant.
The project involves a total investment of some 200 million dollars.

Introduction
The Ramos field is located in the forest alp-like region of the province of Salta towards the Northwest of our country. The reservoir under consideration was discovered by YPF through the drilling of Well Rxp 11 at a depth of 4400 meters in the year 1976. (Figure 1).
Field development started in 1979 through the drilling of Wells R12 and R15.
Pluspetrol Energy S.A. (previously Pluspetrol S.A.) operates the field as from 1980, being entitled to a 60% share interest in the Ramos Consortium formed by Tecpetrol S.A. (25%) and Astra CAPSA (15%).
Since taking possession of the production area, the Consortium drilled another seven wells and a horizontal branch was drilled in Well R.15, the current potential being 7.00 MM m3/day.