bluuebunny/crossref_metadata_2025 huggingface dataset:
Determination of Residual Oil Saturation After Waterflooding
Authors: Cordiner F.S. , Gordon D.T. , Jargon J.R.
Published: December 2007

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

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

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

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

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

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

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

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

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

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

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.
Evaluation of Oil and Gas Companies
Authors: Choudhary Bijoy K.
Published: December 2007

Acquisition plays an important part for most companies in their continued growth, expansion and diversification. Oil and gas companies are no exception. There are numerous methods and yardsticks for evaluation of oil and gas properties and/or companies. The aim, in each case, is to arrive at a fair market value of the properties based on the information available.

A systematic approach is presented here for a quick, easy and accurate evaluation of an oil and gas company. The criteria of profitable acquisitions lie in understanding the basic concepts of discounted cash flow, rate of return, etc. Two computer programs are described - one to evaluate oil and gas properties and the other to analyze financial state of the company. Income tax, write-offs, cost of money, etc., should also be considered before reaching a final value.

Introduction

Very few papers have been published on the evaluation of oil and gas companies from the engineer's point of view. The papers cover only a general outline of the procedure to be followed. The details are not spelled out.

This paper presents a brief discussion into all aspects of engineering and financial evaluations of oil and gas companies. One does not have to have a strong financial background to understand, to interpret and to make intelligent use of the financial data available on a company. The subject matter is described in three parts, namely, engineering evaluation of the properties, financial analysis of the company and consideration of some of the other factors.

PROPERTY EVALUATION This is the first step of any evaluation of an oil and gas company. To arrive at a fair market value of its properties, the reserves of oil and gas are estimated and a reasonable production forecast is made. The geological production forecast is made. The geological and engineering considerations take into account location of the field, type of structure, net pay, type of formation, past performance, pay, type of formation, past performance, productive capacity of the wells, recovery productive capacity of the wells, recovery schemes, e.g., waterflood, gas injection, different types of solvent flood, thermal recovery methods, etc. The future production forecast depends on domestic demand, exports, etc. For example, in Alberta, Canada, the Energy Resources Conservation Board sets the allowable based on demand for oil in Canada and exports to the U. S.
Risk Analysis - An Aid in Evaluating Reservoir Development Alternatives
Authors: Goodknight R.C. , Thachuk A.R.
Published: December 2007

In this paper we present an exposition of Risk Analysis as it is applied to a reservoir development problem, mention the statistical notions involved, compare the work required to obtain a Risk Analysis versus a Conventional Cash Flow Analysis, and compare results for a reservoir development application.

The vehicle for the presentation is a reservoir development decision couched in terms familiar to the audience. The problem at hand is to decide whether or not to invest in a waterflood. We determine those additional data that are available to the decision maker using Risk Analysis to quantify the profitability of his alternatives as compared to results available using Conventional Cash Flow Analysis.

With the aid of a reasonably flexible computer program, the benefit of a Risk Analysis applied to a reservoir development decision can be obtained at practically no additional cost for analysis. Considering that significant cost is usually involved in the gathering of data and the definition of the relationships among the factors influencing a reservoir development decision, the additional quantification due to Risk Analysis has a very high return on the work involved.

Introduction

The thesis of this paper is that Risk Analysis is a simple extension of conventional profitability analysis, that the incremental profitability analysis, that the incremental cost of Risk Analysis is relatively small and that the rewards are relatively large. Our approach will be to define conventional profitability analysis and Risk Analysis for profitability analysis and Risk Analysis for the purposes of this paper, to present the one concept required in order to extend a conventional profitability analysis into a Risk Analysis, and to present an example application.
Optimizing Mature Oil Fields Through the Utilization of Alternative Artificial Lift Systems
Authors: Eson Rod
Published: December 2007

As producing oil and gas properties mature, the nature of the produced fluids change. Water cuts often increase, gas volumes and gas quality change, reservoir pressures decline and mechanical problems generally increase due to the advancing age of the wells. As a result, the artificial lift system initially selected for a well, lease and/or field may not be the most efficient as a field matures. However, once an operator has paid the capital to install artificial lift, many times the lift system in place is simply adjusted in an attempt to meet the changing well production characteristics. The following describes the effort of a progressive thinking, independent oil and gas producer in the re-evaluation of an artificial lift system in a field developed by an urban drillsite. The producing environment of the drillsite requires that special attention be given to the size, electric consumption and potential noise generated by the artificial lift systems being evaluated.

Not only is the process of evaluating specific artificial lift methods to be utilized for a given well described herein, but also how each wells production can effect the operation of an urban drillsite. As properties mature, and especially if they change ownership, operators tend to make changes to existing lift systems and process facilities. As a result, often times a property is inefficiently operated, which can lead to premature abandonment. It is demonstrated herein, that a superior approach to maintaining the status quo is to consider the best method of lift and fluid processing for current, and anticipated future production trends. In this way, the unit cost of producing the two urban drillsite described herein was reduced by nearly 75% which increased reserves by more than 2000%. The urban drillsite described is located in the Rideout Heights area of the Whittier field.
Origin and Maintenance of Abnormal Pressures
Authors: Louden Lester R.
Published: December 2007

A review of the origins of pressures and a restatement of the definition of abnormal pressures is presented. Geologic interactions are presented as supporting evidence for the basic origins. A discussion of the various geologic maintenance theories are presented with supporting evidence.

Text

The term "abnormal pressure" through general usage has come to mean higher-than-normal pressure encountered in the earth's crust while drilling. Some have defined these pressures as geopressures.

Normal is defined as the lithology gradient for a salt water basin. If so, we must accept any deviation from 0.465 psi/ft of depth as abnormal. Therefore, any fresh water or brackish water deposition must be called abnormal. There exists a normal for every geological setting, but since we drill far more wells in sediments associated with sea water deposition, 0.465 psi/ft of depth will be used as normal in this discussion.
Enhancing Frac-Pack Evaluations With Directional and Spectral Gamma Ray Measurements
Authors: Gadeken L. L. , Fox P. A. , Brumley J. L. , Wehunt C. D. , Thurston F. K. , Nasution R. D.
Published: December 2007

The effectiveness of frac-pack operations can be easily monitored by using radioactive tracers. The fluid and solid components of materials placed downhole can be tagged with different gamma-ray-emitting isotopes. After the pumping operations have been completed, specialized gamma ray logging sondes can be run in the well to establish the precise locations of the tagged materials. Directional gamma ray measurements determine the azimuthal placement distributions. Gamma ray spectral energy measurements allow the contributions of individual isotopes to be separated so that the vertical extent and radial displacement efficiency of the individual components pumped can be established.

This technology can be used to evaluate frac-packs and most other downhole placement operations. The knowledge of where materials are actually placed during downhole pumping operations provides unique diagnostic information. This allows subsequent operations to be improved and made more effective as necessary.

This paper reports on frac-pack operations in the shallow, unconsolidated sands of the Duri field in Indonesia. Gamma ray spectroscopy and directional gamma ray logs were run in several wells as part of a study to determine frac-pack performance.

The gamma ray directional logs show a number of significant asymmetries where sand was apparently placed on one side of the wellbore. There was some evidence of "ballooning" in several zones where the frac-pack pushed the formation sand away from the borehole. The gamma ray spectroscopy logs offered supporting evidence which was confirmed by additional laboratory analysis. The interpretation of all the gamma ray log results confirmed the frac-pack operations. The log results also provided evidence regarding the detailed manner in which the frac-pack was placed and gave rise to some adjustments to enhance frac-pack procedures.

This project demonstrated that frac-pack technology resulted in increased oil production and utilization of frac-pack operations will continue. However, maintenance requirements were not reduced as much as desired because of proppant flowback. Methods for further reducing costs are being investigated.
Applying NMR Total and Effective Porosity to Formation Evaluation
Authors: Coates George R. , Menger Stefan , Prammer Manfred , Miller Miller
Published: December 2007

The porosity of a reservoir and its water saturation fraction have long been at the heart of wireline and MWD log based formation evaluation. In many formations, however, the complexity of the mineralogy and the properties of the formation's conductivity have only permitted qualitative answers. This has even been true with evaluations based on multi-log data suites.

At the 1996 SPE Conference a new NMR logging process, the MRIL®* C/TP system, was introduced. C/TP provides a measure of total porosity independent of mineralogy and dependent only on the hydrogen density of the fluids themselves.

This represents a significant advantage over the conventional density, neutron, and acoustic ‘porosity’ logs, which mostly respond to rock properties. Furthermore, the C/TP amplitude can be subdivided into pore size groups associated with clay mineral bound water, capillary bound water and pores free to accumulate hydrocarbon (FFI).

Usage of the MRIL has proven the benefit of a borehole-centralized log, a feature that makes it largely independent of borehole size and shape. It has also become recognized as the first porosity log that truly measures the pore system and not some inference of porosity based on the rock matrix.

Thus the log analyst is provided with a wireline log that is truly a porosity log which provides a quantitative measure of total and effective porosity.

To investigate the accuracy and reliability of these methods and ideas, well bore data are assembled and compared to conventional log and core results. A full description of these comparisons and processes are included to show the benefit of a true porosity measurement that is insensitive to matrix mineralogy and only depend on pore size and fluid contents,the advantage of a porosity measurement largely independent of borehole condition.
Paraffin Deposition from Crude Oils: Comparison of Laboratory Results to Field Data
Authors: Hammami Ahmed , Raines Michael A.
Published: December 2007

In this study, we evaluate the characteristics of four reservoir fluids sampled from two offshore fields in the Gulf of Mexico as well as their propensities towards paraffins deposition due to temperature and/or pressure variations. State-of-the-art techniques, namely a cross polarized microscopy (CPM) and a laser-based solids detection system (SDS), have been used to measure the onsets of paraffin crystallization temperatures, also known as wax appearance temperatures (WAT) and/or cloud points. The results are presented, discussed and compared to reported field data. Explanations for the observed differences and/or similarities between laboratory and field WAT are proposed.
Effect of Water Breakthrough on Sand Production: Experimental and Field Evidence
Authors: Skjærstein Anne , Tronvoll Johan , Santarelli Frederic J. , Jøranson Håvard
Published: December 2007

It has been reported from different field operators that the onset of sand production in a particular field coincided with water breakthrough at the production wells. Several mechanisms have been proposed to explain these observations such as pore pressure gradient increase near perforations due to relative permeability effects, reduced capillary bond due to increased water saturation, and loss of rock cohesion because of chemical incompatibility between produced water and the reservoir rock.

Yet, there does not seem to exist any systematic study of such a phenomenon on a large scale, neither capable of supporting any of the proposed mechanisms nor the statement that the onset of water breakthrough may trigger the onset of sand production.

As a consequence, a vast campaign of physical model experiments of perforation cavities using field and outcrop material was undertaken to observe directly the effect of water breakthrough upon the onset of sand production. The experiments, have convincingly demonstrated that the two phenomena could not be linked directly, but that once sand production has initiated, water production could accelerate the sand influx thus making it more noticeable and problematic for daily operations.

Finally, the problem of the coincidence of water breakthrough and onset of sand production has been analysed on a series of more than 40 oil and gas wells in weak sand reservoirs. This analysis of field data further confirms the laboratory and theoretical findings described in the paper.
Hello, This is Your Gas Well Calling
Authors: Maloney D. R. , Haley J. W.
Published: December 2007

Imagine being able to survey production from gas wells while at home, the office, or even while traveling. Think of the advantages of a system that automatically calls soon after an alarm condition is detected at a site. A measurement and communication system that provides these services is already in operation in New Mexico, Oklahoma, Texas, and a portion of Kansas.

This paper describes GPM Gas Corporation's innovative electronic gas flow measurement, telemetry, and telecommunications system. It can provide hourly measurements from over 17,000 electronic flow measurement (EFM) meters, which track the delivery of over 1.9 billion cubic feet of gas each day through more than 26,000 miles of gathering lines. Users have many options for obtaining gas rate, pressure, and temperature data, including automated voice reports over the phone, fax services, and data downloads from the database and network. The system simplifies many functions such as gas rate measurements, custody transfers, compensation, and scheduling of field services, allowing producers and GPM to take advantage of near real-time information for optimizing operations and reducing costs.

The system serves as an excellent example of how telecommunications can improve operations through integrating data collection and information management.
Thermodynamic Micellization Model for Asphaltene Precipitation from Reservoir Crudes at High Pressures and Temperatures
Authors: Pan Huanquan , Firoozabadi Abbas
Published: December 2007

Asphaltene precipitation from reservoir crudes has been modeled using liquid-liquid equilibrium; the precipitated heavy phase is assumed to be in the liquid state and to consist of only asphaltene and resin. The light liquid phase is assumed to consist of the monomers of all the components and the micelles. A thermodynamic micellization model and the Peng-Robinson equation of state (EOS) description of all monomers fully specify the thermodynamic equilibrium state. From the direct minimization of the Gibbs free energy of the liquid-liquid system, the composition and the amount of each of the phases are calculated.

The above model is used to calculate precipitation from three different reservoir crudes. Once vapor-liquid equilibrium parameters are obtained, there is no further adjustment of the parameters of the EOS for precipitation calculations. The predictions from the thermodynamic micellization model are in good agreement with data. The effect of pressure, temperature and composition on precipitation is properly predicted by the model.
Coupling Fluid-Flow and Geomechanics in Dual-Porosity Modeling of Naturally Fractured Reservoirs
Authors: Chen Her-Yuan , Teufel Lawrence W.
Published: December 2007

The purpose of this study is to formulate a coupled fluid-flow/geomechanics model of a naturally fractured reservoir. Fluid flow is modeled within the context of dual-porosity (more generally, overlapping-continuum) concept while geomechanics is modeled following Biot's isothermal, linear poroelastic theory. The development follows along the line of the conventional and existing porous fluid-flow modeling. The commonly used systematic fluid-flow modeling is therefore preserved. We show how the conventional fluid-flow dual-porosity formulations are extended to a coupled fluid-flow/geomechanics model. Interpretation of the pore volumetric changes of the dual continua, fractures and matrix-blocks, and the associated effective stress laws are the most difficult and critical coupling considerations. New relations describing the dual rock volumetric changes are presented. These relations allow a smooth and consistent transition between single-porosity and dual-porosity concepts and are in terms of measurable quantities. Reduction to the single-porosity is presented to demonstrate the conceptual consistency of the proposed model.
Inflow Performance and Transient Pressure Behavior of Selectively Completed Vertical Wells
Authors: Yildiz T. , Cinar Y.
Published: December 2007

This paper presents new methods to estimate the inflow performance and transient pressure behavior of selectively completed vertical wells. In the first part, inflow performance of wells perforated at several intervals along the producing formation is investigated experimentally and theoretically. Theoretical investigation is based on an analytical solution. An arbitrary number and pattern of open intervals with different skin values are considered in the analytical model. An electrical analog was constructed to verify the productivity model. The productivity model compared very well with the experimental data obtained from the electrical analog apparatus. The parameters controlling well productivity are identified through a sensitivity study. Well completion strategies to achieve optimum well productivity are discussed. It is observed that formation anisotropy, total perforated length/formation thickness ratio, and mechanical skin distribution due to formation damage are the parameters controlling the well productivity.

In the second part, transient pressure and pressure-derivative response of selectively perforated wells are modeled and examined. The wellbore storage effect and non-uniform skin effect are included. A new interpretation technique which combines the conventional semilog straightline analysis and type-curve matching method is presented to determine reservoir parameters. It has been observed that the effective mechanical skin is a time-dependent parameter. In case of selectively completed vertical wells, pseudoskin is interrelated to mechanical skin distribution due to formation damage around the wellbore. If rate distribution along the wellbore is available from production logging, horizontal and vertical permeabilities, total skin factor and its components, effective mechanical skin and pseudoskin, can be determined uniquely. The proposed interpretation technique is used to analyze the well test data.
Huff-n-Puff Technologies for Water Production Control: Analytical Reservour Modelling
Authors: Holleben Carlos , Bedrikovetsky Pavel
Published: December 2007

The injection stage of huff-n-puff polymer process is described by the traditional model for polymer flooding. During the production stage, the irreversibly adsorbed polymer is trapped by the reservoir oil, and the amount of polymer trapped by oil is an additional unknown for the mathematical model of the process. So, the traditional model is not applicable any more. Laboratory tests performed show that the trapped polymer can significantly reduce the permeability for oil. A new mathematical model for the polymer huff-n-puff process honouring the adsorbed polymer trapped by the reservoir oil, is developed. 1-D models for huff-n-puff processes have been developed for cases of the use of oil and of polymer as displaced fluids.
Short Radius Directional Drilling, when Combined with Project Planning, Drilling Efficiency and Geosteering, is a Valuable Production Enhancement Tool
Authors: Nitis Ike , Askew Warren
Published: December 2007

Short radius drilling has not yet reached its full potential in the global market. To prepare for the perceived increase in activity for this technique, systems have been developed to adapt to a variety of hole conditions and target requirements. The systems, designed around positive displacement mud motors and a flexible MWD, have been successfully deployed in many areas of the world.

Drilling the short radius well efficiently is only one aspect of an integrated series of events, all of which must be orchestrated and performed correctly to guarantee the financial success of the project. Particularly in areas where short radius and re-entry drilling is a new experience, the directional driller, as the technical driver, is involved in aspects of the planning and operation which traditionally are not in his domain.

This paper reviews the development and status of the short radius drilling systems, and discusses related operations which affect the outcome of the project.
Using Concrete Technology to Improve the Performance of Lightweight Cements
Authors: Moulin Eric , Revil Philippe , Jain Bipin
Published: December 2007

To successfully cement across and isolate formations with low fracture gradients requires the use of lightweight cement slurries. Conventional lightweight slurries usually have a high water-to-solid ratio, which results in long waiting-on-cement times, limited compressive strength development, and a relatively permeable cement sheath subject to acid and brine attack. A new approach to designing cement slurries effectively decouples the physical properties of set cement from the slurry properties and density, resulting in high performance lightweight cement slurries that reduce rig time and the logistics and costs associated with using conventional slurry designs. This has been clearly demonstrated in the cases of completing in reservoirs with a low fracture gradient (eliminating the risk of block squeeze), replacement of two-stage cement jobs by a single stage, and the use of a single slurry to replace lead/tail cement and side-track plugs. Results are described from various field applications where the technology has been used.
First Successful Multilateral Well Installation From a Floating Rig: Development and Case History
Authors: Freeman Austin , Gronas Tore , Berge Frode , Durst Doug , Luke Mike
Published: December 2007

This paper details the design, development, testing, and installation of the first successful multilateral well installed from a floating rig offshore Norway. Well design constraints were evaluated with respect to their impact on a multilateral well. These constraints included rig heave affecting multilateral operations, horizontal junction placement, unconsolidated junction/reservoir rock, and requirements for a cemented junction. Potential problems were determined, and materials and processes were developed to provide resolutions for these problems. Testing was performed to verify that the solutions planned would be successful. New developments for the project included a rate-of-penetration controller tool and a new fluid-loss-control device. Other firsts included the use of a single hollow whipstock to mill the casing window as well as treatment of the junction area with a consolidating chemical to improve stability and reduce the tendency for sand production.

The multilateral well was constructed according to plan with no serious problems and is currently producing from both laterals.

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