bluuebunny/crossref_metadata_2025 huggingface dataset:
Experience Using Microbubbles-Aphron Drilling Fluid in Mature Reservoirs of Lake Maracaibo
Authors: Ramirez Francisco , Greaves Roberto , Montilva Julio
Published: December 2007

The objective of the paper is to present field results obtained through the evaluation of the Micro-bubble Aphron system, as the drilling fluid in wells VLA-1321, VLA-1325, VLA-1326, VLA-1327, VLA-1329, VLA-1331, VLA-1332, VLA-1334 and VLA-1335 (wells corresponding to Lagomar Integrated Laboratory). This fluid does not require equipment such as compressors, rotary wellhead, equipment to generate and/or inject nitrogen and permits the taking of electric logs conventionally.

During drilling, mud weight varied between 6.8 to 7.9 ppg and very low-pressure zones were run through, with equivalent gradients oscillating between 2.4 ppg and 6.4 ppg, without any problems of loss of circulation.

The micro-bubble fluid presented excellent inhibition values to clay and shale since the Miocene sands of Basal La Rosa and the alternating sand and shale of the Eocene reservoirs were drilled without any problems. Moreover, in well VLA-1321, this lithology was with an exposure time of 25 days, without any instability problem. On the other hand, in wells VLA-1329, VLA-1331, VLA-1332, VLA-1334 and VLA-1335 all the intervals were drilled from 1520’ to 6900’, without using intermediate casing and without great problems, which cut down drilling time to 31.0 days with a saving of 4.7 MMUS$ for the corporation.

It should be pointed out that the fluid has presented rheological properties, which have permitted drilling with excellent hole cleaning.

During the drilling of well VLA-1321, 90’ of samples were taken in the Miocene and 300’ in the Eocene sands with a high percentage of recovery (90.80%) and in well VLA-1326, 411’ of samples were cut with a percentage of recovery of 90.4%.

Additionally, the electric logs were not affected by the micro-buble mud and caliper logs showed a hole of excellent gage.

Judging from the excellent results obtained, the Micro-bubble Aphron system is still being evaluated in the Eocene mature reservoirs of Lake Maracaibo.
Formation Damage Due To Sulfur Deposition in Porous Media
Authors: Shedid Shedid A. , Zekri Abdulrazag Y.
Published: December 2007

The existence of sulfur compounds in crude oils creates many problems of sulfur deposition in the vicinity of wellbore hole, in well completion and/or production equipment, and in producing reservoir rocks.

The major objectives of this experimental study are to investigate the influences of oil flow rate, initial sulfur concentration of crude oil, and reservoir rock permeability on elemental sulfur plugging in carbonate oil reservoirs. To achieve these objectives, actual crude oils were de-asphaltened to eliminate the effect of asphaltene deposition. Ten dynamic flow experiments were conducted using two actual crude oils of 0.78 % and 1.67 % sulfur concentrations. Viscosity of crude oils of different sulfur concentrations was measured under different conditions of temperature. The crude oils were flooded through actual carbonate cores of different permeability in the range of 2.34 to 28.16 millidarcy and under different flow rates of 0.5, 1.0, 1.5, and 2.0 cc/min. In-situ sulfur deposited was measured using Scanning Electron Microscope (SEM) to provide the amount of sulfur deposited along the core samples.

The results indicated that crude oil of higher sulfur concentration has higher viscosity than that one of lower concentration. The deposition of elemental sulfur does not take place at low rate of 0.50 cc/min, starts at 1.0 cc/min and increases as the flow rate increases up to 1.50 and 2.00 cc/min, respectively. In addition, the higher of sulfur concentration of the crude oil increases the deposition of sulfur in carbonate oil reservoirs. The results also showed that permeability of carbonate reservoir rocks has a severe effect on sulfur deposition since carbonate rocks of higher permeability does not experience the problem of elemental sulfur deposition while the problem is more severe for lower permeability rocks. In addition, the depositional rate is accelerated rapidly as the rock permeability decreases.

The obtained results of this study have important interest in identification the most important factors affecting the elemental sulfur precipitation in heterogeneous carbonate oil reservoirs and robust implications in the development of reservoir simulation models.

INTRODUCTION AND REVIEW

Many gas/oil reservoirs suffer of having large amounts of hydrogen sulfide and other sulfur compounds. Sulfur occurs free in the elemental state. Precipitation of elemental sulfur within reservoir rocks can impair oil productivity and thus affects economic feasibility negatively. Sulfur compounds are considered as the most important non-hydrocarbons in crude oils, because of (1) their corrosive nature, (2) their deleterious effects of petroleum products, (3) their attendance to plug porous medium, which may impair formation productivity, (4) their effect on oxidation characteristics, and (5) their disagreeable odor.
High-pH Clay Instability Rating
Authors: Gdanski Rick
Published: December 2007

It is commonly understood that clays have surface hydroxyls that are available for various interactions. The magnitude of the interactions possible because of the natural acidity that clays possess has been previously demonstrated.1 Laboratory experiments using a 3-ft Hassler sleeve and unconsolidated sand/clay-packed columns demonstrated that the pH profile of buffered and unbuffered high-pH fluids can be readily understood as the result of two dominant mechanisms. The first mechanism is neutralization by the natural clay acidity. The second mechanism is the attack of hydroxide on clays and is demonstrated in this paper. The rate of hydroxide attack is temperature, clay, and pH dependent. The rate constants were used to develop a high-pH Clay Instability Rating (CIR) for the clays tested. The impact of CIR on injected-fluid pH profiles was numerically demonstrated with the new model for both linear and radial flow. These two geometries are relevant to leak-off during frac-packs (linear) and for drill-in fluids and matrix treatments (radial).
An Experimental Study for Mechanical Formation Damage
Authors: Soares A. C. , Ferreira F. H.
Published: December 2007

This paper presents a new methodology to evaluate mechanical formation damage due to drilling and oil production. The methodology covers a wider range of stress path adding new insight to fluid flow analysis in porous media. In some reservoirs occur large deformations during oil production due to the increasing of effective stresses. This may cause permanent damage to the reservoir, as the rock structure changes, lowering the permeability and the final oil recovery. A series of rock mechanics tests were carried out, including velocity measurements of P and S waves. These tests showed that plastic behavior is always present and that a yielding region occurs and that it may be represented by the cap model. This methodology allowed a near wellbore evaluation and permeability investigation using stress path concept.
An Experimental Investigation of Fracture Propagation During Water Injection
Authors: Suárez-Rivera Roberto , Stenebråten Jørn , Gadde Phani B. , Sharma Mukul M.
Published: December 2007

Water injection for pressure maintenance, waterflooding or disposal of produced water has become an important issue in the management of produced fluids. However, suspended particles in the injected water cause formation damage and can lead to fracture initiation due to an increase in injection pressure. Injectivity decline in injection or disposal wells can have a large impact on the economic feasibility of water disposal operations. Fracture propagation could potentially result in undesirable environmental and reservoir engineering consequences.

The paper presents results of a study conducted to understand the mechanisms of injectivity decline and fracture propagation during water injection. Large-scale injection tests were conducted under simulated in-situ stress and pore pressure conditions, using rock blocks 27″×27″×32″, representative of a consolidated reservoir rock and laboratory-made produced-water.

Results indicate that the rate of fracture growth is strongly dependent on the type and concentration of particles in the injected fluid. The shape, size and compressibility of the injected particles play an important role. Our results clearly demonstrate that the injectivity remains almost constant once a fracture is initiated. The injected particles are filtered largely near the tip of the fracture where the leakoff is the highest. The depth of penetration of the particles into the matrix appears to be small. Analyses using optical microscopy observations on thin sections show that the filter cake is not a continuous film but rather a region (from 3 to 10 grains deep) where the connected flow paths have been effectively blocked by solid particle deposition. Results from these experiments provide a basis for developing analytical and numerical modeling tools for injectivity decline and fracture propagation in fractured injectors.
Adjustment of Hydraulic Fracture Design in Gas-Condensate Wells
Authors: Indriati Shirley , Wang Xiuli , Economides Michael J.
Published: December 2007

Hydraulic fracturing has been the stimulation/completion method of choice to enhance production for the vast majority of natural gas reservoirs throughout the world. However, the post-treatment behavior of hydraulically fractured gas and gas-condensate reservoirs is complex. This work addresses important aspects of this behavior.

Many natural gas reservoirs exist in the region of retrograde condensation. During production of hydraulically fractured wells, the pressure gradient formed between the reservoir pressure and the flowing bottomhole pressure is likely to result in liquid condensation normal to the fracture face and extending at considerable distance into the reservoir. This leads to an unavoidable reduction of the relative permeability-to-gas, a phenomenon, which was correlated, based on preliminary experimental results that has been obtained. Such a relative permeability reduction depends on the phase behavior of the fluid and the penetration of the liquid condensate into the reservoir. The latter depends on the pressure drawdown imposed on the well. This situation causes a well performance impairment, which behaves as if an apparent damage, tantamount to fracture face damage has affected the fractured wells. Well testing of such wells invariably calculates much shorter apparent lengths than actually placed.

This work proposes a model that predicts the performance of hydraulically fractured gas condensate reservoirs (quantifying the effects of gas permeability reduction), adjusts fracture treatment design, calculates the optimum fracture morphology and presents guidelines for the calculation of the optimum pressure drawdown during production to maximize well performance. While these issues are important in all gas reservoirs they become particularly crucial in higher-permeability cases.
Predicting Brine Mixing Deep Within the Reservoir, and the Impact on Scale Control in Marginal and Deepwater Developments
Authors: Mackay E. J. , Jordan M. M. , Torabi F.
Published: December 2007

Sulphate scale deposition is a common problem in hydrocarbon reservoirs where injection seawater, rich in sulphate, mixes with formation brines, rich in barium, strontium and calcium. The deposition of these scales can cause significant production impairment if it occurs within zones near the production wellbores. To control scale deposition within the near wellbore region of a reservoir, scale squeeze treatments are commonly deployed. In cases where the scale severity is very high, removal of sulphate ions from the injection water is an alternative scale control strategy. Both these methods of mitigation have associated CAPEX (e.g. desulphation plant) and OPEX (e.g. scale squeeze treatments) costs.

Typically, to assess the severity of the problem in new fields, thermodynamic calculations are performed to calculate the mass of scale that will form. Until present there has been little work carried out to identify the location of scale formation within the reservoir. In this paper, field data and flow simulations from three North Sea fields are presented to show that the formation of scale can in fact occur deep within the reservoir, and have negligible negative impact on oil production within the near wellbore region.

Evidence is presented from these North Sea fields that shows the evolution of the brine chemistry as seawater breakthrough occurs and squeeze treatments were applied. The evidence from the produced brine chemistry is linked to flow calculations for these fields to show that in some systems scale is depositing deep within the reservoir, reducing the potential for damage in the near production wellbore region. The extent and impact of the deposition varies throughout the reservoir and can be quantified. The ability to model brine mixing and stripping of the scaling ions before the fluids reach the production wellbore has a very significant impact on the economic assessment of marginal fields and deepwater developments. In such fields, the technical challenge and cost (CAPEX/OPEX) of scale control might make development un-economic. This paper outlines the data requirements and methodology used to allow such an assessment to be made.
Injection-Induced Hydraulic Fracturing in a Naturally Fractured Carbonate Reservoir: A Case Study from Saudi Arabia
Authors: Azeemuddin M. , Ghori S. G. , Saner S. , Khan M. N.
Published: December 2007

A case study involving power water injection in the fractured Arab-D carbonate reservoir in a Saudi Arabian field is discussed. The study was conducted to investigate the role of injection operations in the initiation and propagation of induced fractures and their communication with nearby faults, and to provide a methodology for early detection of the induced fracturing process.

The study involved analysis of data gathered from step-rate, falloff, flowmeter tests, as well as injection rate and pressure data over the history of the injection operation, followed by well test modeling and hydraulic fracture modeling (HFM).

Most of the eight wells studied showed the existence of fractures, corresponding to a rise in injection pressure beyond the fracturing gradient or formation parting pressure (FPP). Skin and injectivity indices obtained from the falloff tests were found to be good indicators of fracturing behavior, based on which most of the studied wells were inferred to communicate with the natural fracture system or super-permeability streaks. HFM showed that induced fractures could reach a half-length of up to 1400 ft, to various heights depending upon the injection rate and permeability. The distance to the nearest fault obtained by superimposition on a 3-D seismic interpretation was found to vary from 500 to 2,000 ft. At high injection rates, fractures were found to grow out of reservoir into underlying tight formation, which could lead to loss of injected water. For controlled fracture height, which may lead to more efficient injection operations, preparation of injection rate guidelines was recommended.
Fractal Formulation of the Porosity and Permeability Relationship Resulting in A Power-Law Flow Units Equation – A Leaky-Tube Model
Authors: Civan Faruk
Published: December 2007

This paper presents a "leaky-tube model" for characterization of flow units and permeability of porous media in terms of the relevant parameters of the interconnected pore space. This is accomplished by representing the flow through porous media using a bundle of leaky-capillary hydraulic tubes/hoses allowing interactions between the hydraulic tubes and the relevant fractal attributes of the interconnected pore structure in real porous media. Civan's power-law flow-units equation is derived by three alternative means. It is demonstrated by comparison to experimental data that this model can accurately represent the permeability vs. porosity data of actual geological porous formations.

This model can be used for convenient means of correlating experimental data and determining the parameters of the flow units of geological porous media by straight-line plots. It can also be used for describing the variation of the flow units in porous media undergoing formation damage and stimulation processes.
Vug Characterization and Pore Volume Compressibility for Numerical Simulation of Vuggy and Fractured Carbonate Reservoirs
Authors: Iwere F. O. , Moreno J. E. , Apaydin O. G. , Ventura R. León , Garcia J. L.
Published: December 2007

Three porosity types, matrix, vugs and fractures, are usually present in naturally fractured, vuggy carbonate reservoirs. The vugs are generally considered connected either to the matrix or to the fractures in numerical simulation. One of the challenges of modeling these reservoirs is the partitioning of the porosities into two components since dual porosity reservoir simulators can only handle two rock components, namely matrix system and fracture system. The goal of this study is to characterize the vugs in these systems, and to determine the pore volume compressibility for the simulation of vuggy, naturally fractured reservoirs.

Sequential laboratory experiments were designed and conducted to determine the amount of secondary porosity in the core samples. A combination of capillary pressure (centrifuge and mercury injection experiments) and NMR experiments was used to determine the vug or secondary porosity of the samples from pore size and T2 (relaxation time) distributions. The results were compared and reconciled with those from porosity logs and image logs. Pore volume compressibility tests and compaction tests were used to determine the compressibility of each sample. The compaction and pore volume compressibility tests were evaluated at different net stresses to determine the influence of vuggy porosity in the samples.

The composite (sample) compressibility versus porosity plots showed that pore volume compressibility increases as secondary porosity increases. This dependence, which is strong at low net stresses, gradually disappears as the reservoir pressure decreases or the net stress increases. This implies that the effects of secondary porosity on pore volume compressibility of the total system are minimal at low reservoir pressures. Based on these results, pore volume compressibility was generated for various values of effective and secondary porosity and served as input data to the numerical flow models. The development of the vug porosity, pore volume compressibility and the construction of the simulation flow model are described in this paper.
The Hybrid Drilling Unit: An Overview of an Integrated Composite Coiled Tubing and Hydraulic Workover Drilling System
Authors: Coats E. Alan , Farabee Mark
Published: December 2007

Since the decline of the cable-tool rig, well construction operations have been performed exclusively with some variation of steel tubulars. Recently a drilling system that combines composite coiled-tubing technology and hydraulic workover technology has been introduced. This paper examines the benefits of the combined system.

A newly developed composite coiled-tubing drillstring with embedded conductors allows this revolutionary drilling system to achieve uninterrupted, real-time, two-way communication with the downhole tools. This allowed a step-change improvement in the knowledge of dynamic wellbore conditions and in the overall control of downhole drilling assemblies and systems. Subsequently, new procedures were developed to assimilate and use this increased functionality. These procedures include both geosteering and real-time system diagnostics from remote locations.

Incorporating a hydraulic workover (HWO) jacking system as an integral part of the unit expanded the operating envelope and functionality of the entire system. The HWO unit allows for jointed pipe drilling in both underbalanced and overbalanced situations. The HWO unit also serves as a platform to perform jointed pipe completions. When combined with the composite coiled-tubing drilling unit, the resultant "hybrid" drilling system greatly expands the options now available for developing hydrocarbon reserves.
A Triple-Mechanism Fractal Model with Hydraulic Dispersion for Gas Permeation in Tight Reservoirs
Authors: Civan Faruk
Published: December 2007

This paper presents a triple-mechanism-fractal model including the hydraulic dispersion effect to more accurately describe the gas flow in tight gas reservoirs than the frequently used Darcy law. By comparison to Darcy's law, this paper demonstrates that the improved formulation presented in this paper is more adequate.

A Darcy-like equation using an apparent permeability is derived by considering the gas transport by three mechanisms, which may occur in tight pore space under different Knudsen number criteria. This equation incorporates the Knudsen, slip, and viscous flow mechanisms into the description of gas flow, each prevailing under different conditions. The characteristics of porous media are represented by fractal equations. The equation of continuity includes the effect of hydraulic dispersion, which has been omitted in the usual reservoir analysis. These equations are solved analytically for one-dimensional, horizontal, and steady flow in laboratory core tests and radial flow in the near-well bore region.

The present analysis indicates that Darcy's law fails to describe the flow of gas in tight formations under the Knudsen and slip flow conditions, because Darcy's law was designed to represent the viscous flow by analogy to liquid flow. Hence, the flow of gases through porous medium should be treated differently than liquids. In addition, the walls of tight pores in porous media interfere with the mean-free motion of gas molecules and cause a strong deviation from Darcy's law. Further, the porous media macroscopic mass conservation equation should include a term for transport by hydraulic dispersion due to mixing and compressibility effects. Therefore, the conventional well test interpretation methods require a correction when the flow occurs under the Knudsen and slip flow conditions. This confirms the significance of the model presented in this paper.

The triple-mechanism with hydraulic dispersion model presented in this paper can be used for accurate and convenient means of describing gas flow in tight-geological porous media undergoing various flow regimes.
Novel Application of Ecological System Drilling Fluid Accomplishes Significant Advances in the Hole Stability Problems
Authors: Héctor Mandujano Santiago , Ramirez Ricardo Lara , Heliodoro Perez Palacios
Published: December 2007

In deep well drilling operations, borehole stability causes severe problems that requires excessive rig time to solve them. The not productive times are about the thirty percent of the total drilling time. The wells located at the south region of Mexico are characterized by being of high pressure and high temperature with surface and intermediate length zones (3500 meters approximately) formed by sands and clays. The incidence of this problem is explained by the rock-fluid interaction "mud - rock". An immediate solution has been the use of oil based muds; however, sandy layers present another problems. An additional problem is the strong ecological restrictions due to Well's geographical location. From three years ago, Pemex has studied the phenomenon through a project called "Improvement in the compatibility drilling fluid-formation" obtaining significative advances.

According to the importance of having a water based fluid that faces conditions, it was necessary to develop a drilling fluid system that could be able to maintain, by an extended period of time, the stability in the clays. From vast laboratory studies to core samples, the Luna field was selected to use a polymeric potassium-silicate drilling fluid. As a result, it was obtained a drilling fluid that maintained an excellent borehole stability during 70 days. This was the best result compared with other systems used in the area. It is of equal importance the fact that the fluid is environmentally friendly.
Strategic Sustainability Integration: The Next Step in the Journey
Authors: Wilcoxon Bruce R. , Cramer David F.
Published: December 2007

Conoco's journey towards sustainability began in earnest about 2 years ago as an "incremental" effort to bring increased awareness of environmental and community responsibility to existing operations. Since then however, the company has evolved to a much richer understanding of sustainable development and its potential. Sustainable development is now considered a strategic framework for long-term business success with the potential to shape the company's direction and is the foundation for Conoco's vision of achieving sustainable business growth. Committing to financial excellence, environmental stewardship and broad, ongoing contributions to social development earns Conoco its license to operate and allows us to embrace new, value creating opportunities by leveraging our capabilities to bring sustainable solutions to our customers and stakeholders. In short, our commitment to sustainable development is seen as a fundamental prerequisite for Conoco's survival and success in the new century.

Like many companies that have embraced the concept of sustainable development, Conoco is now embarking on the challenge of translating that vision of economic, environmental and social sustainability into the reality of tangible value creation and sustainable growth. Strategic sustainability integration represents a shift in mindset away from traditional regulatory compliance, risk abatement, and cost control into the realm of opportunity identification. The purpose of this paper is to discuss Conoco's experience with strategic sustainability integration in its operations from around the world. Examples will describe community development efforts in Nigeria, the positive environmental impact of a natural gas project in Syria, as well as an integrated approach to extra-heavy oil development the environmentally sensitive Orinoco Oil Belt of Venezuela. These and other efforts represent the beginning of Conoco's journey towards strategic sustainability and total economic, social, and environmental value creation.
Causes of Injectivity Problems During Fractured Water Disposal and Their Remediation
Authors: van den Hoek P. J. , Khatib Z. I. , Siemers G. J.
Published: December 2007

For many years, all the untreated production water from the Groningen gas field in The Netherlands had been injected into a dedicated water disposal well without problems. Recently, however, the injectivity of this well reduced significantly as a result of downhole blockages. Various remedial injection well clean ups and acidisations were executed without much long-lasting success. Early 2001, a dedicated study was conducted to identify the causes of the problems and come up with remedial actions. In particular, the question was whether the well plugging was due to the the low quality of the injection water, which would imply building dedicated water treatment faclities in order to remediate the problem, or whether the blockages were due to some other mechanism.

By carrying out a thorough analysis of all the injection data over the years, and combining this analysis with water injection computer simulations, it was concluded that the injectivity problems had nothing to do with the low injection water quality, but were the result of sand production during shut-ins. This result appeared surprising at first sight as the disposal water is injected into a fairly competent sandstone. It led to a set of recommendations for an improved way of operating the disposal well. The recommendations have been followed up, as a result of which the well has been in operation trouble-free over the last six months.
Coreflood Studies to Examine Potential Application of Novel Scale Inhibitor Products to Minimise Intervention During Field Life Cycle
Authors: Jordan M. M. , Collins I. R. , Gyani A. , Graham G. M.
Published: December 2007

With the development of more and more subsea fields, the challenge for scale inhibitor squeeze treatments is to reduce intervention frequency by extending squeeze treatment lifetime whilst concomitantly reducing any potential damage in both low water cut and higher water cut wells. This paper discusses the technical problems and examines new technologies for treatment of such production wells through their life cycle.

Scale control technology available to control scale formation within the reservoir and near-wellbore area of production wells will be outlined with a focus on the current developing technology to control scale within low water cut wells. Moreover, it is shown that the new technical area of emulsion scale inhibitor delivery systems, originally designed to control scale within low water cut wells, has application in both low and high water cut wells

This study assists in developing an understanding of the mechanism of interaction of emulsion-based products; in particular the impact of the level of water saturation within the core system. In addition, it demonstrates that the emulsion particles are retained in the core matrix during both crude and brine flowback. This paper indicates that the emulsion product offers the potential for extremely long squeeze lifetimes with minimal damage in oil production wells with rising water cut. It also demonstrates how different technologies have their own place in the life cycle of a production well.
A Rigorous Formation Damage Skin Factor and Reservoir Inflow Model for a Horizontal Well
Authors: Furui K. , Zhu D. , Hill A. D.
Published: December 2007

In this paper, we present a new analytical model for formation damage skin factor and the resulting reservoir inflow that includes the effect of reservoir anisotropy and damage heterogeneity. The shape of the damaged region perpendicular to the wellbore is based on the pressure equation for an anisotropic medium, and is thus circular near the well and elliptical far from the well. This assumption gives an appropriate skin factor even for a small penetration of damage. The new model can be used for any distribution of damage along the well. The new skin factor model can be easily incorporated into any existing model of reservoir inflow for a horizontal well.

We also present a new reservoir inflow equation for a damaged parallelepiped-shape reservoir drained by a horizontal well. This equation shows that the ratio of the reservoir thickness to the drainage length perpendicular to the well is a very important factor for determining the influence of formation damage on horizontal well productivity because the linear flow geometry becomes dominant for a thin reservoir. The larger the ratio of thickness to drainage length perpendicular to the well axis, the larger the influence of nearwell formation damage on well productivity.

In examples presented in the paper, a truncated elliptical cone of damage with a larger penetration near the vertical section of the well (at the heel) is presumed to compare our model with an existing horizontal well damage skin factor model. The comparisons show that, for an anisotropic reservoir with shallow-penetrating formation damage, our model avoids the negative skin result calculated by the previous model and predicts higher skin factor than the existing model. For deep damage, the new model predicts lower skin factor than the previous model.

The impact of formation damage on the overall production is also shown in examples. In general, the effect of near well formation damage for a horizontal well completion is relatively small compared with vertical wells. However, if the reservoir thickness is large, radial flow becomes dominant and the impact of formation damage on a horizontal well is more significant, more like that of a vertical well. Our model gives a simple, analytical expression for determining this effect.
Residual Gas Saturation to Aquifer Influx: A Calculation Method for 3-D Computer Reservoir Model Construction
Authors: Holtz M. H.
Published: December 2007

Residual gas saturation controls the volume of gas trapped in that portion of the reservoir that has experienced water encroachment. As water moves into a rock volume filled with gas, the water displacement of the gas is incomplete. The water fills pores and pore throats, causing capillary pressure and relative permeability effects to stop the flow of gas and allow only water to pass through the rock volume. This stoppage results in gas being trapped behind the encroaching waterfront as residual gas. The volume and location of the residual gas are controlled by the distribution of the petrophysical properties.

A method based on interrelationships between petrophysical properties is used to create a model for calculating maximum residual gas saturation (Sgrm). The model is developed as a function of porosity, permeability, capillary pressure, and initial water saturation. The input to the model and its results compare favorably with actual field data where aquifer encroachment is verified from well production history.
Methane Number Control of Associated Gas from Oil Production
Authors: Ohlrogge K. , Zettlitzer M. , Hartmann U. , Boße D. , Wind J. , Brinkmann T.
Published: December 2007

The paper deals with filed experiments to control the methane number of associated gas, which was used as fuel gas to operate a gas engine. The methane number has a strong impact on the anti-knocking behavior of the fuel gas. A membrane separator equipped with elastomeric membranes separates the higher hydrocarbons from the associated gas. In dependence of the gas source and the ambient temperature the methane number of the gas fluctuates. A methane number higher than 50 was required to ensure a smooth operation of the Otto carburetor engine. Operating experiences with the pilot unit will be discussed as well as membrane data and design criteria for a commercial plant.
Material Balance as a Horizontal Line for a Gas-Condensate Reservoir
Authors: Hsieh Frank S. , Vega Cecilia , Vega Lucy
Published: December 2007

Straight-line material-balance plots are commonly applied to analyze reservoir performance and estimate the OHIP (original-hydrocarbon-in-place). Depending on the type of the straight-line plot is applied the OHIP may be found either from the slope or the intercept of the straight line. In the case of a gas-condensate reservoir, the compositional effect and the overpressure effect must be formulated into a general material-balance equation to obtain a valid straight-line plot. For obtaining a correct OHIP a line must be both linear and having the correct slope or intercept when straight-line material-balance plots are used. Unfortunately, a quality material-balance evaluation for a gas-condensate reservoir is difficult to achieve using straight-line material-balance plots because the additional data required for calculating the compositional effect and the overpressure effect are difficult to obtain. This paper illustrates that the compositional effect and the overpressure effect can be ignored if the results obtained based on a general material-balance equation are plotted as a horizontal line. In horizontal line material-balance plot no slope or intercept is used as the condition for determining the OHIP because only a correct OHIP can give a horizontally linear material-balance plot, the only condition to meet. Horizontal-line material-balance plots simplify the evaluation procedure and improve the quality of material-balance valuations.
The Interplay of Forces and Their Strength on Fluid Flow in Gas Condensate Reservoirs
Authors: Ursin Jann-Rune
Published: December 2007

Production from gas condensate reservoirs is characterized by condensation of gas and liquid dropout, first in the near wellbore volume, then as a region dynamically developing into the reservoir. The effects of liquid condensation are reduced productivity and loss of production. Successful forecast of well productivity from gas condensate reservoirs depends on proper understanding of the various forces acting on fluid flow in time and space. Production form these reservoirs is thus indirectly related to the interplay of fundamental forces, such as; inertial, viscosity, capillary and gravity, and their relative strengths, demonstrated through various dimensionless numbers.

Dimensionless numbers are defined and calculated for all pressure and space coordinates in a test reservoir, thus defining various dynamical regions where certain forces are dominating over others. Identification of these regions in a reservoir facilitates use of pseudo permeability functions, which again should be correlated to interplay of forces.

Material balance -, reservoir fluid flow - and wellbore flow calculations are performed on a cylindrical reservoir model. The ratios between fundamental forces are calculated and dimensionless numbers are defined. The interplay of forces, demonstrated by these numbers, are calculated as function of radial dimension and reservoir pressure. Comparisons of the different dimensionless numbers are performed and gas permeability is evaluated in the test case.
On the Characterization of Carbonate Reservoirs Using Low Field NMR Tools
Authors: Mai A. , Kantzas A.
Published: December 2007

Alberta contains significant deposits of oil and gas in carbonate formations. Carbonates tend to have fairly tight matrix structures, resulting in low primary porosity and permeability. As a result, laboratory characterization of carbonate properties is a slow and tedious process. Low field NMR is an emerging technology shows great promise in rock characterization. In a single NMR experiment, rock properties like porosity, permeability and Swi can in theory be measured.

Experiments were performed on approximately 80 core plugs from six carbonate formations. Porosity measurements were performed through gas expansion and brine saturation (Archimedes’ principle). Air permeabilities were also measured. Cores were also saturated with brine and spun to irreducible water saturation. NMR measurements were taken at both saturation stages (Sw = 1.0 and Sw = Swi). NMR data were interpreted using the conventional core analysis results as guides. Observations were made regarding NMR trends and corresponding rock properties.

Preliminary analysis of the data shows that NMR can successfully predict the content and distribution of the fluids in the porous media. Also, the NMR spectra of carbonate samples seem to suggest that NMR can be used as a tool for classifying cores into different pore systems.

Using T2cutoff values as a tool, the cores can be divided into groups. Group 1 has T2cutoff < 80 ms, while group 2 has T2cutoff in the range of 80 to 200 ms and group 3 has T2cutoff values > 200 ms. Group 1 cores generally have higher porosity values than groups 2 and 3. Group 1 also has low values of T2gm, compared to the other two groups. Air permeability was compared to the geometric means and T2gm_cutoff values of the three groups and some general trends were observed, but more analysis is required before these trends can be quantified.
Multivariate Fracture Treatment Optimization for Enhanced Gas Production from Tight Reservoirs
Authors: Rahman M. M. , Rahman M. K. , Rahman S. S.
Published: December 2007

An excessive high treatment pressure may be required to execute a production enhancing hydraulic fracture treatment in a tight-gas reservoir, particularly if the treatment is designed with inappropriate values for treatment parameters: fracturing fluid viscosity, injection rate, injection time and proppant concentration. Such a high treatment pressure may not only exceed the delivering capacity of specified surface equipment (pump, pressure rating devices and downhole tubing), but may also cause multiple fracture initiation. Multiple fracture initiation may cause near-wellbore tortuosity complexities and large fluid loss, and thus may damage the formation irreversibly that results in productivity lower than even unfractured wells. This paper presents an integrated model for multivariate fracture treatment optimization with adequate trade-offs between production enhancement, equipment capacity and formation compatibility requirements. The model considers both fracture geometry (length, height, width etc.) as well as treatment parameters as free design variables. Compatibility relationships between reservoir properties, treatment parameters and fracture growth are formulated using a modified pseudo-3D fracture model. Design constraints are formulated to ensure that the final optimum design is compatible with specified equipment and formation characteristic to avoid the above-mentioned fracture complexities. The optimal design of fracturing treatments to maximize cumulative production is demonstrated in the paper by a series of applications of the model to a tight-gas reservoir. Sensitivity results of various parameters are also presented in the paper.
Severity of Water Coning in Gas Wells
Authors: Armenta M. , Wojtanowicz A.
Published: December 2007

Theoretical study, reported in this paper, qualifies unique mechanisms of water coning in gas wells. Water coning in gas wells has been understood as a phenomenon similar to that in the oil wells. It is shown, however that both the water inflow mechanism and its impact on well's productivity are substantially different. It is shown, for example, that, after water breakthrough, the oil-water interface at the well's completion would continue to cone, while the gas-water interface reverses at the top of the cone.

Analyzed in the paper are the results of a conventional simulation of water coning in gas wells showing that water could affect productivity only at the very late stage of well's life. However, field data, shown in the paper, evidence early and severe water problems. This contradiction is explained in the paper by including the effects of Non-Darcy flow, perforation density and the ratio of vertical-to-horizontal permeability in modeling of water coning in gas wells. Results from numerical simulation combined with analytical models show that an early water breakthrough and a considerable increase in water production may result from combined effects of increased vertical permeability, lower density of perforation and high-velocity gas flow around the wells.
Application Of The Ion Exchange Process To Reservoir Preflushes
Authors: Griffith T. David
Published: December 2007

Introduction

The ionic environment of a reservoir is important in micellar flooding and in any other process where ion sensitive agents, such as caustic process where ion sensitive agents, such as caustic or wettability alteration fluids, are flooded through a reservoir. Ton exchange can have a major, if not the controlling influence on the composition of brines in petroleum reservoirs.

Ion exchange operations are chemical reactions between an electrolyte (the ions) in solution and an insoluble electrolyte (the clays) contacted by the solution. Clays in reservoirs behave as ion exchangers. Normally, they are in equilibrium with the reservoir brine. When fluids of a different composition, not in equilibrium with the clays, contact the clays, an exchange of ions between the clays and the fluid takes place until the two are in equilibrium. The exchange is primarily with cations (positively charged ions) primarily with cations (positively charged ions) with little, if any, anion (negatively charged ions, such as chloride) exchange occurring. To preserve electrical neutrality, the exchange is preserve electrical neutrality, the exchange is stoichiometric with respect to the charges of the ions. Material balances show that two monovalent cations (sodium) are exchanged for one divalent cation (calcium).

A relatively hard though fresh Madison water has been injected during the waterflood of the Second Wall Creek Reservoir of the Salt Creek Field. The reservoir is working as a large water softener, exchanging the calcium and magnesium from the injected water for sodium on the clays. The result is that the clays near the injectors have been hardened by the Madison water, while the clays near the producer can still remove the divalent ions and soften the injected water. This hardening process can be reversed by injection of a soft brine containing low levels of calcium and magnesium. This process is analogus to the regeneration of a water softener. Injection of a micellar fluid more saline than the Madison water would reverse the process causing high concentrations of hardness which could be detrimental to an ion sensitive micellar fluid.

The purpose of this paper is to present experimental data and model studies showing how the ion exchange process has affected and will affect the Second Wall Creek reservoir. A method for preflushing the reservoir to remove the divalent ions is also presented. Additional insights into the ion exchange process and the nature of the ion equilibrium are discussed.

Background

Theory

The ion exchange reaction is described by Equation 1

(1)

as a reversible chemical reaction between free ions (Na and Ca) in solution and ions adsorbed on the clays where X is an ion exchange site. To preserve electrical neutrality, two monovalent preserve electrical neutrality, two monovalent (sodium) ions exchange for one divalent (calcium) ion. The clay ion exchange sites can be thought of as a separate chemical species involved in the reaction.
Fracture Stimulation Optimization in the Redevelopment of a Mature Waterflood, Elk Hills Field, California
Authors: Walker Tom , Kerns Shawn , Scott Dick , White Paul , Harkrider John , Miller Craig , Singh Tarlochan
Published: December 2007

This paper is a case history describing fracture optimization of low-permeability highly-stratified stacked turbidite sandstone reservoirs of the B interval of the Elk Hills Field. The occurrence of high-permeability, high-pressured water saturated sands immediately above and/or below the objective oil sands poses a major challenge.

Integration of improved petrophysical understanding, geoscience techniques, hydraulic fracture model calibration and on-site, real-time execution has achieved a two-fold oil production increase in the south east nose area of the field while limiting water production to a 40% increase. Downhole tiltmeter measurements are incorporated to calibrate the fracture model and limit fracture height growth, thus regulating fracture conductivity to the oil saturated reservoirs, and minimizing contact with the adjacent wet zones.

To date, results from surface tiltmeter1 measurements completed during twenty six fracture stages have been used with the downhole tiltmeter2 data and reservoir characterization to optimize the ongoing redevelopment from a peripheral waterflood to a pattern flood.
Rapid Seismic Screening and Probabilistic Economic Methodologies for Prioritization of Targets
Authors: Toelle Brian E. , Chi Dah-Ruey David
Published: December 2007

The current energy environment has refocused attention on many exploration areas in Alaska. The resulting flood of new data for these areas will require rapid evaluation for the bidding rounds. New innovative approaches can help companies rapidly screen 3D seismic and prioritize prospects. Aided by the preliminary risked reserves and economic analysis, management can gain insights into the monetary worth of an area in order to make investment decisions.

The QuickSEIS 3D seismic screening process has been applied to a number of areas in the Gulf of Mexico. In an integrated process, seismic attributes are generated and blended in various combinations, and examined with modern visualization technology that allows the major structural and stratigraphic features to be identified and defined in terms of their geometry and attribute anomalies.

While Alaska’s geology is significantly different from the GOM, this technique is applicable. Combined with probabilistic economic methodologies leads to an overall reduction of project cycle time. This is especially important for areas like Alaska where a huge amount of capital is often involved.