bluuebunny/crossref_metadata_2025 huggingface dataset:
Production Casing Erosion through Annular Injection
Authors: Richardson J. W. , Le K. M. , Riggs K. R.
Published: December 2007

Normal waste fluids disposal in North Slope, Alaska oilfields includes large-scale underground injection through well annuli. This cost-effective disposal method has produced severe erosion in some production casings. A series of tests were run to quantify significant parameters that cause erosion: fluid volume, fluid velocity and sand content. From the observed erosion rates, the calculated wear equation constants were found to be consistent with other published values. As a result of the test described below, several steps have been implemented to reduce casing erosion: reducing injection rates and volumes, monitoring sand content, and changing casing head outlet configuration.
Analysis of Mass Transfer Mechanisms Occurring in Rich Gas Displacement Process
Authors: Lee S-T. , Lo H. , Dharmawardhana B. T.
Published: December 2007

This paper aims to understand and quantify the mass transfer mechanisms occurring in a rich-gas injection EOR process. The analysis is based on results from laboratory experiments and one-dimensional compositional simulation work.

First, different laboratory tests, involving reservoir oil and solvent, are presented to illustrate their application to a preliminary understanding of in-situ solvent-oil mixing behavior and development of a proper equation-of-state (EOS) fluid characterization. Second, one-dimensional compositional simulation work based on the calibrated EOS was conducted to validate the simulator and the EOS by comparing the experimental slim tube data with the simulation predictions. Third, practical examples are presented to illustrate the various mass-transfer mechanisms that could occur during rich gas displacements.

For certain pressure, temperature and solvent-composition conditions, a miscible or critical fluid was predicted to occur in a slim tube. Furthermore, the critical fluid could occur either at the tail-end or at the front of the transition zone. The former case would confirm the mechanism of the classical condensing-drive multiple contact miscible process. The latter case has also been discussed recently in the literature for rich gas displacements.

At the prevailing reservoir conditions of interest, however, the displacement was a near multiple-contact-miscible process, characterized by a condensing-vaporizing mass transfer sequence and by a high oil recovery close to that of a multiple contact miscible process. Details of the switching from a condensing to a vaporizing process were investigated.

Finally, this work shows that, quite similar to the CO2-vaporizing drive processes, solvent density requirement can be an important parameter for preliminary screening of solvent compositions for rich gas projects.
Experimental Evaluation of Transition Metals Salt Solutions as Additives in Steam Recovery Processes
Authors: Rivas O. R. , Campos R. E. , Borges L. G.
Published: December 2007

It is well documented by laboratory and field data that besides physical changes such as viscosity reduction with temperature and steam destilation, the steam injection processes are accompanied by chemical reactions which, as it has been the case in the M-6 steam drive project in the Bolivar Coast of Lake Maracaibo, produce large amounts of undesirable hydrogen sulphide gas. Depending on the type of crude and on the steam temperature, they can also produce an irreversible increase or lowering of crude oil viscosity.

To in-situ control the hydrogen sulphide production and to promote the lowering of the crude oil viscosity, it has been proposed to use transition metals salts solutions such as nickel sulphate as additives in steam injection processes. In this work, we present the results of an experimental study carried out to assess the effect of using such an additive.

The experimental plan consisted of both static and dynamic test. The concentration of the solution was varied to 1.5 wt. % nickel sulphate at a temperature of 240°C, typical of Venezuelan steam injection projects. Reconstituted and whole core samples from two Venezuelan bitumen reservoirs were used.

Obtained results show that the two bitumen samples undergo aquathermolysis, in presence or absence of reservoir sand, that results with reconstituted sands are similar to those obtained with whole core samples and that the use of the additive promotes a lowering in bitumen viscosity, both in static and dynamic test. In the dynamic tests, however, changes are more pronounced in shorter reaction times. In one case the oil viscosity was lowered 20 times.
Prediction of Xanthan Rheology in Porous Media
Authors: Cannella W. J. , Huh C. , Seright R. S.
Published: December 2007

The flow behavior of xanthan in porous media has been investigated experimentally, and also theoretically using effective medium theory. In the experimental portion of this study, the rheology of a commercially-available xanthan broth was characterized in porous media and viscometers and compared for a wide range of polymer concentrations (300 to 1600 ppm), effective brine permeabilities (40 to 800 md), residual oil saturations (0 to 29%), temperatures (25° and 80°C), and rock lithologies (sandstones and carbonates). An apparent shear rate equation having no adjustable parameters was developed and proved to be effective in relating the flow behavior of a given polymer solution in porous media at one set of conditions to the behavior at all other porous media conditions tested as well as to the rheology in a viscometer. Although the shear rate dependence on flow velocity (first order) and effective permeability (negative one-half order) agrees with that predicted by traditional capillary bundle model approaches, the value of the experimentally determined constant coefficient is larger than those predicted by the models.

The basis for the shear rate equation employed above has been studied theoretically with the assumption that the xanthan solution rheologies approximately follow the power-law relation. The apparent viscosity for a power-law fluid flowing in a porous medium is derived employing the effective medium approximation of percolation theory. In this approach, a porous medium is modeled as a network of capillary tubes, in which the radii of tubes are randomly distributed using a prescribed probability distribution. The apparent viscosity expression obtained is similar to that from the capillary bundle model, but the coefficient values are different, as observed experimentally. This difference is a consequence of the connectivity of flow channels and their variable cross-section. Due to its shear-thinning nature, a power-law fluid flows mainly through the wide channels of porous media, and largely bypasses small-scale pore channels of the porous body. The capillary bundle model cannot describe this tendency of a shear-thinning fluid.
Computed Tomography Studies of 3-D Miscible Displacement Behavior in a Laboratory Five-Spot Model
Authors: Withjack E. M. , Akervoll I.
Published: December 2007

This paper presents the results of computed tomography (CT) studies of three-dimensional (3-D) miscible displacements in a laboratory five-spot model. In the field, gravity forces resulting from a density difference between a miscible agent (solvent) and a reservoir oil may cause segregation and result in an overriding solvent tongue. The laboratory model used in these experiments is a one-quarter of a five-spot pattern (20 cm × 20 cm × 15 cm) with a porous medium constructed of spherical glass beads. Viscous and gravity forces are scaled within certain limits to represent conditions applicable to the field.

Displacements are conducted at mobility ratios of 7.5 and 22.4 over a range (approximately 2 to 23) of viscous-to-gravity force ratios (Rv/g). Previous five-spot recovery correlations, based on a combination of 2-D areal and 2-D vertical sweepout, are found to overestimate recovery for the 3-D displacements. At one pore volume injected, for example, recoveries range from approximately 10% to 30% lower than those indicated by earlier correlations. In contrast with 2-D behavior, recovery efficiency increases continuously with greater Rv/g. The displacement characteristics for 2-D flow typically show a single overriding solvent tongue; the 3-D displacement characteristics observed here typically include an overriding tongue with secondary fingers. These results provide new experimental data in true 3-D geometry, and reinforce concerns with extending previous 2-D concepts to flow in 3-D five-spot patterns.
Design of a Propagating Wave Resistivity Sensor in Order to Minimize the Influence of Borehole Fluids on the Sensor Response
Authors: Rodney P. , Bartel R.
Published: December 2007

A propagating wave electromagnetic resistivity sensor has been developed which exhibits superior performance in low resistivity muds compared to the sensor previously available. The development of this sensor was a result of a careful analytical and experimental investigation of borehole effects on electromagnetic wave sensors. In its introduction, this paper summarizes the observed effects of borehole diameter and resistivity on the response of electromagnetic wave resistivity sensors; details follow in the body of the paper. Following this, a presentation is made of the experimental and theoretical methodology used to establish borehole correction curves. This method was used to optimize the response of an electromagnetic wave sensor and to develop a general model for the borehole response of electromagnetic wave sensors. This is an extremely simple mathematical model; because of its simplicity, it is significant that it works (using different coefficients) for both the improved and the older electromagnetic wave sensors. Borehole correction curves, as predicted by the model for both sensors, are in excellent agreement with experimental data over a wide range of mud resistivities. Accordingly, an accurate set of borehole correction curves is presented for both sensors. From these curves, it is apparent that borehole effects on the improved electromagnetic wave sensor are small to negligible for borehole diameters up to 12 1/4 inches and mud resistivities as low as .02 ohm meter.

It has been reported that an MWD focused current type of device will provide more immunity to borehole effects when mud resistivity is very low than will an electromagnetic wave sensor. A comparison between the response of the improved electromagnetic wave sensor, that of an MWD focused-current resistivity sensor and of a lateral type of sensor demonstrates that this need not be the case. Finally, a logging example is presented in which the improved and original electromagnetic wave sensor responses are compared. This example also confirms the relative insensitivity of the improved propagating electromagnetic wave sensor to borehole effects.
Drawdown Well Test Analysis for Multicomponent Hydrocarbon Systems
Authors: Thompson L. G. , Vo D. T.
Published: December 2007

Drawdown pressure and phase rate data from retrograde condensate reservoirs are analyzed to obtain estimates of individual phase molar composition, phase effective permeability and sandface saturation as functions of wellbore pressure (or total flowing time). The results of the latter two calculations are combined to construct an effective permeability/phase saturation relationship which reflects the in situ reservoir flowing conditions. Data from reservoirs which are damaged, undamaged, stimulated, and for which the initial reservoir pressure is close to the dewpoint pressure are considered.

Methods of estimating reservoir absolute permeability and skin factor from measured drawdown pressure/sandface phase rates and known initial reservoir fluid composition are also presented. These methods do not presume availability of relative permeability curves, and as such should enjoy greater ease of applicability to field data analysis than presently available methods.
Prediction of Geochemical Formation Damage in the Vicksburg Formation of South Texas
Authors: Riese W. C. , Riese A. C.
Published: December 2007

Formation damage is broadly considered to be the occlusion of pore throats by debris. This occlusion is generally thought to result from the introduction of fine-grained particles to the formation, or the migration of particles already present in the formation. We contend, however, that particles and cements may be precipitated in situ by disruption of geochemical equilibrium in the reservoir.

The Olivarez #2 well was completed in the Oligocene Vicksburg Formation (Z-sand), using a KCI-based completion fluid and was traced using a fluid of similar composition. The well began to unload and flow immediately and was killed using 14ppg CaBr2. Some damage was suspected to have occurred at this point because the initial production tests did not see flow rates comparable to other wells in the field. A second frac of the formation was then undertaken using CaCl2/CaBr2-based fluids, but no significant improvement in flow rates was realized.

Our analysis of this problem focused on rigorous geochemical modeling of the reservoir and the changes that would be induced if fluids were added to the reservoir fluid-rock system. Calculations accounted for activity coefficients via the extended Debye-Huckel relationship and for elevated temperatures by the van't Hoff or Kirchoff equations. Geochemical analysis of reservoir environments utilizing these equations yields a more accurate picture than can be reached using Stiff-Davis or similar approaches. Consideration of sulfates, carbonates, and silicates concurrently is also only possible with this type of analysis.

The results of our modeling indicate that the loss of KCI-based completion fluids to the formation may have resulted in the precipitation of both carbonate and silicate phases within the formation. Subsequent attempts to improve deliverability by tracing produced no improvement because the loss of CaCl2- and CaBr2-bearing fluids to the formation during kill and tracing procedures apparently caused additional silicate-phase precipitation.

We recommend geochemical reservoir characterization as a critical part of proper reservoir management. Such work, when done in a timely fashion, can help predict the tendency of a reservoir system to produce irreparable precipitate damage. This type of work may also help curtail the use of costly clean-up or stimulation procedures where the geochemistry of the system will render them ineffective.
A Direct Deconvolution or Convolution Algorithm for Well Test Analysis
Authors: Roumboutsos A. , Stewart G.
Published: December 2007

A numerical Laplace Transformation based on a piecewiзe linear approximation to a function has been developed. The convolution of fundamental pressure and flow transforms yields variable rate pressure responses. The deconvolution process involving the quotient of transforms allows the equivalent constant rate response to be determined from measured pressure and rate data. This provides a general basis for the treatment of variable rate well tests in heterogeneous systems. The inversion of products or quotients of Laplace transforms is carried out by numerical inversion algorithms, usually the fast method due to Stehfest. The application of deconvolution to buildup tests is considered. Synthetic and field examples are used to illustrate the application of the techniques.
"Reservoir Description: A Practical Synergistic Engineering and Geological Approach Based on Analysis of Core Data"
Authors: Amaefule J. O. , Kersey D. G. , Marschall D. M. , Powell J. D. , Valencia L. E. , Keelan D. K.
Published: December 2007

Description of reservoir rocks in terms of complex variations in hydraulic properties, heterogeneity and geometry requires a synergistic, multidisciplinary engineering and geological approach.

This paper presents a practical systematic approach to integration of various core analysis data for reservoir description. Various petrophysicai parameters are strongly correlated with pore space attributes using the mean hydraulic radius, K/∅. Additionally, empirical equations are presented for transforming lab-derived core properties to appropriate reservoir in-situ stress conditions.
Characterization of a Naturally Fractured Carbonate Reservoir: Lisburne Field, Prudhoe Bay, Alaska
Authors: Belfield W. C.
Published: December 2007

A synthesis of data from cores, production logs, well tests, and well performance is used to provide both a preliminary description and an estimate of parameters necessary for numerical simulation of a naturally fractured, multi-layered carbonate formation under primary depletion.

Core fracture analysis indicates the presence of open fractures immediately beneath an unconformity surface that marks the top of the formation. The interpretation that these fractures provide substantial permeability is confirmed by spinner logs (which indicate large decreases in productivity short distances below the unconformity) and injection surveys (which show large quantities of injected fluid being accepted by the formation just below the unconformity). Rapid pressure response between adjacent wells during an interference test is attributed to this fracture system. The fracture system is believed to be spatially related to the unconformity surface. Other fractures recognized in core are partially open and appear to be discontinuous on a core scale. These fractures are believed to enhance matrix permeability rather than act in the manner of fractures associated with a dual-porosity system.

Production in the reservoir is from both fractures and from vertically extensive.

better quality matrix zones. Partitioning the total permeability-thickness (kh) value between these two modes of productivity is problematical. Matrix kh can be estimated by using log porosity and a core derived porosity/permeability transform. Justification for this approach is found in approximately linear semi-log plots of permeability versus porosity of full-diameter cores measured under overburden stress.

Total kh values (determined from pressure transient tests) are cross-plotted with productivity indices for a series of wells. A straight line fit to the data is considered to be representative of Lisburne well productivity. Use of this plot permits an estimate of total well kh for any well in the field, given a calculated productivity index. Corresponding apportionment of fracture kh and matrix kh can then be made for the well. This approach greatly expands the data base available for inferring effective fracture or fracture kh distributions beyond that determined from limited core and well-test data.
Beam Pump Motors: The Effect of Cyclical Loading on Optimal Sizing
Authors: Durham M. O. , Lockerd C. R.
Published: December 2007

The performance of motors changes when the motor is applied to cyclic loads. The effective horsepower and efficiency is reduced. A method of calculating the effective ratings is presented. A comparison of operations on both conventional and unconventional pumping units is outlined.
Flow Regimes in Vertical and Inclined Oil/Water Flow in Pipes
Authors: Zavareh F. , Hill A. D. , Podio A. L.
Published: December 2007

Flow regime behavior in upwards oil-water flow has been studied in a large diameter, inclinable, multiphase flow loop. With the pipe vertical, bubble flow occurred for all conditions tested. When the pipe was inclined by 5 or 15° from vertical, a new flow regime, countercurrent bubble flow, was observed over a wide range of flow conditions. Theoretical flow regime maps developed for gas-liquid flow did not properly predict oil-water flow regime behavior.
Intelligent Pigging of the Ekofisk-Emden 36-in. Gas Pipeline
Authors: Nespeca G. A. , Hveding K. B.
Published: December 2007

The Intelligent Pigging of a major gas pipeline requires careful planning and execution to obtain successful results as well as to maintain production and to avoid disruption of gas contract commitments. Although it is costly to implement such inspections, the information obtained can be invaluable to the operation and is a vital part of the maintenance program of a strategic North Sea gas transmission pipeline. This paper describes the preparatory work, actual performance and findings obtained from an inspection using a "state of the art" magnetic flux inspection vehicle.
Reduction of Jet Perforator Penetration in Rock Under Stress
Authors: Halleck P. M. , Saucier R. J. , Behrmann L. A. , Ahrens T.
Published: December 2007

Tests using multi-shot perforating guns in large 3/4 × 3/4 × 9/10 m blocks of stressed rock have been used to quantify stress-induced penetration reductions for three different charges. All three charges were tested in Berea Sandstone, one charge was tested in Bedford Limestone. The fractional reduction in penetration depends on charge design, size and rock type. In tests with elevated pore pressure, data best fit an effective stress law, P(effective) = P(confining) – P(pore). Larger fractional penetration reductions were observed for a small charge (10-cm rock penetration). This may be partially explained by correlating penetration with hoop stress near the wellbore rather than with mean effective stress.

Two methods are considered to predict the observed penetration reductions. First, changes in acoustic velocities with pressure are correlated directly with penetration depths. Thus, log or core data may be useful in predicting downhole penetration. Second, a penetration model that includes the effect of target strength under confining stress is evaluated. The latter theoretical analysis results in a charge-dependent semi-empirical parameter related to impact pressure. The value of this parameter is less for the smaller Charge A than for Charge B. The ability of this simple theory to reproduce observed penetration reductions suggests that a more sophisticated treatment may be able to predict downhole perforator performance directly from the characteristics of a given charge.
Enhanced Recovery of Coalbed Methane through Hydraulic Fracturing
Authors: Holditch S. A. , Ely J. W. , Semmelbeck M. E. , Carter R. H. , Hinkel J. , Jeffrey R. G.
Published: December 2007

Hydraulic fracturing has been used to accelerate removal of methane from coal seams ahead of underground mines. Originally, all of the gas that was produced was flared or vented. Over the past decade, however, there has been a growing awareness of the vast potential for recovery of methane gas from coal seams. This awareness is leading to the commercial exploration and development of coalbed methane reservoirs in many areas of the U.S.

Coalbed methane production is viewed as a new and significant energy source. Associated methane gas from coal is now the primary source of natural gas for the state of Alabama and is rapidly becoming a major source of natural gas in the San Juan Basin of New Mexico and Colorado.1–6 The natural gas industry is still learning how to complete wells and produce gas from coal-seam reservoirs. Compared to our knowledge of techniques for the completion and production of sandstone and limestone reservoirs, our knowledge in coal-seam reservoirs is minimal, at best.

The success achieved in producing gas from shallow coal has encouraged some operators to explore for gas trapped in deep coal seams that will never be mined. One area of significant activity is the San Juan Basin. To optimize recovery from most of the wells drilled into deep coal seams, hydraulic fracturing treatments are required. Experience has shown that the design and execution of fracture treatments in coal seams is not straightforward. High injection pressures, complex fracture systems, screenouts and the production of proppant and coal fines after the treatment are typical problems facing the operator.
Horizontal Drainhole Drilling Techniques Used for Coal Seam Resource Exploitation
Authors: Logan T. L.
Published: December 2007

Methane gas contained in coal represents a potential new gas supply. Transformation of this large gas-in-place resource to reserves will depend on developments of modified and/or new completion methods to achieve long-term economic production. Coal reservoirs typically have very low matrix permeability with gas being desorbed from the matrix to the wellbore through a system of natural fractures or cleats. Due to low permeability, coal reservoirs usually require hydraulic fracture stimulation to achieve economic production. Investigations have shown that hydraulic fractures usually propagate parallel to the maximum stress or face-cleat direction and therefore may not adequately access an anisotropic reservoir. A more effective stimulation technique may be a horizontal borehole placed perpendicular to the maximum permeability direction. This paper discusses the short-radius and medium-radius directional drilling techniques that have been used to successfully place horizontal drainhol es into coal seams.
Insights into Hydraulic Fracturing of a Horizontal Well in a Naturally Fractured Formation
Authors: Layne A. W. , Siriwardane H. J.
Published: December 2007

Horizontal wells are thought to be necessary in formations with low-permeability such as the Devonian shales to increase natural gas recovery and to reduce the risk of drilling a dry hole. In a horizontal well, the bore hole crosses multiple natural fractures in the reservoir. Stimulation data from a 2,000 ft (609.6 m) horizontal well drilled into the Devonian shales in Wayne County, West Virginia, was used in this study. Inflatable packers and casing port collars were used so that individual zones could be tested or stimulated along the wellbore.

This paper focuses on an analysis of hydraulic fracture design and geometry predictions for the above horizontal well. Current hydraulic fracture modeling theories address failure mechanisms and the propagation of a single crack from a vertical wellbore. These theories have been adapted to predict the pressure, flow rate, and induced fracture geometry for each natural fracture intersected by the hydraulic fracturing fluid in the horizontal wellbore. A tubing/annulus flow model was coupled with a hydraulic fracture model that predicts the three-dimensional geometry of multiple natural fractures propagating from a horizontal well. Additionally, a closed-form solution was developed to predict the pressure and flow rate distribution along the lateral extent of the wellbore.

Predicted results were compared with in situ fracture diagnostics from gas (nitrogen and CO2) and foam stimulation treatments. Radioactive-tracer with spectral-gamma-ray logging confirmed that both fluid pressure and stress perpendicular to the fracture affect the injection flow rate distribution along the wellbore. Both of these factors were used as governing mechanisms for fracture geometry predictions in the simulation model. Predictions based on these models and tracer logs confirm that the single crack theory for fracture propagation is not applicable for stimulations that are initiated along an isolated part of a horizontal borehole.
Drainage Study in the Carthage (Cotton Valley) Field
Authors: Schell E. J.
Published: December 2007

The Carthage (Cotton Valley) Field contains many massive low permeability sands and covers over 200,000 acres. The field development occurred in stages, first on 640 acres and later on 320 acre spacing. Union Pacific Resources Company operates approximately 21,000 acres and has been studying the Cotton Valley since early in the field's development. Infill well performance and initial pressure tests indicate that the existing wells' drainage areas are probably less than 182 acres. Numerical simulation on a typical well shows that the drainage area averages 67 acres for all the sands. Infill drilling on a smaller well spacing will be required to effectively and efficiently deplete this reservoir.
Decline Curve Analysis for Multiphase Flow
Authors: Fraim M. L. , Wattenbarger R. A.
Published: December 2007

In this study, the production from a well in a solution-gas drive reservoir with interstitial water flow from the transition zone is converted to a slightly compressible liquid for analysis on current decline type curves. Integral transforms for time, pressure, and rate have been created to linearize the diffusivity equation for multiphase flow for certain reservoir conditions. The integral transform variable is called an ‘equivalent liquid’ variable and it has the same units as the original variable. All the dimensionless definitions using equivalent liquid variables use initial properties.

This method concentrates on accounting for the effect of the saturation gradients on the rate-time profile as the bubble point moves out into the reservoir and for the effect of changing fluid properties after late infinite acting flow. The radius of investigation is extended so that it accounts for the change in fluid and rock properties around the wellbore during high rate production periods. This extended definition can be used to calculate the time when boundary dominated flow is seen at the well.

‘Pseudo’ relative permeability curves are created for the reservoir drainage volume. We show their shapes will not be similar to the core determined relative permeability curves because the ‘pseudo’ curves include the effects of saturation and capillary pressure gradients.

The effects of gravity segregation, capillary pressure, a skin zone, and some types of formation permeability hetergeneities are examined for the pseudo relative permeability curves and the radius of investigation.
A Generalized Approach to Determine Properly any Aquifer Influence Function in an Analytical Form
Authors: Molinard J-R. , Le Bitoux P. , Fasanino G. , Tek M. R.
Published: December 2007

The production-pressure performance of any producing or storage reservoir depends upon the influence exerted by the surrounding aquifer. Such an influence is mathematically represented by an "influence function" which obviously depends upon the specific geometric and reservoir properties, and upon the boundary conditions of the aquifer. With the exception of a few simplified geometries and a homogeneity hypothesis, the influence function is not generally available in analytical form. There have been methods suggested in the literature, however, for the calculation of such influence functions numerically from production-pressure data.

The purpose of this paper is to expose a general method for the determination of an analytical form of the influence function, no matter how complex the geometry and other characteristics of the surrounding aquifer may be. This analytical form, ∑  aie-bit is a finite series of exponential terms of time and is the proper representation of transient flow as well as long-term behavior. The general method proposed here can easily account for complex flow patterns and situations, such as: –heterogeneities of the aquifer zone,–vertical refeeding by drainance, and–a fractured aquifer zone.

In addition, the use of the analytical form of the function requires much less CPU time than the methods developed up until now to deal with transient flows. At last, the paper includes: –validation of the method in cases where known solutions exist (Van Everdingen and Hurst function, f or example).–various real-world applications for 1D or 2D aquifers with different kinds of boundary conditions.–solutions to complex engineering problems using this method.
Numerical Modeling of Gas and Water Injection in a Geologically Complex Volative Oil Reservoir in the Lake Maracaibo Area, Venezuela
Authors: Silva R. J. , Niko H. , van den Bergh J. N. , Sancevic Z. A.
Published: December 2007

MARAVEN S. A., a subsidiary of Petroleos de Venezuela S. A. is operating the majority of Eocene reservoirs in the Maracaibo basin. The CLC, a large volatile oil accumulation of the deep Eocene C, presently undergoing primary depletion, will most likely need additional recovery processes. A multidisciplinary study was therefore carried out within the framework of the Joint Research Agreement between Maraven/Intevep/Shell with the objective of arriving at the best recovery scheme.

The preparatory phase of the study involved process simulations which demonstrated that the vaporising gas drive prevailing under gas injection could be modelled sufficiently accurate using the volatile oil version of a black oil simulator. This was extensively checked by simulations in both 1-D and 2-D, using ternary diagram versions of compositional reservoir simulators. The main problem confronting reservoir simulation in this area is, however, how to realistically describe heterogeneities. The wide well spacing in these Eocene sandstone reservoirs precludes meaningful correlations on a well-to-well scale. Therefore, a probabilistic technique was used to create likely reservoir architectures in the form of detailed 2-D cross-section whilst still honoring measured well data.

The resulting detailed reservoir models were used to simulate likely performance under water and gas injection. Results indicate that water injection is a very safe process, as both capillary and viscous crossflow from highly permeable into tight layers create a rather even flooding profile. On the other hand, gas injection is very sensitive to internal heterogeneities and vertical permeabilities.

Various routes of lumping reservoir properties to arrive at coarser models for large scale field modelling were also attempted. The usefulness has been demonstrated of the concept of dynamic pseudo relative permeabilities/capillary pressures for simplying such complex sandstone reservoir models whilst still maintaining sufficient accuracy.
Prediction of Hydrocarbon Pore Volume With Uncertainties
Authors: Berteig V. , Halvorsen K. B. , Omre H. , Hoff A. K. , Jorde K. , Steinlein O. A.
Published: December 2007

Prediction of the hydrocarbon pore volume with uncertainties provide important support for decisions concerning development of petroleum reservoirs. A stochastic modelling approach is used to obtain improved predictions and uncertainties. Spatial aspects and qualified guesses from the user is included in the model. Consistency with existing wells is ensured. A case-study is presented. The .92 confidence interval is found to be approximately 95% of the average value with one well present and approximately 24% of the average with eight wells present.
Removal and Abandonment: Cost Reduction by Forward Planning
Authors: Carruthers D. R.
Published: December 2007

The paper will show how cost reductions during Removal & Abandonment (R&A) can be achieved by forward planning. The planning will necessitate a greater depth of thought, but will not involve a significant increase in either capital, or operating cost.

Current design and operating practice pay little attention to the problems of eventual removal and abandonment. By recognising the impact of decisions taken during design, installation, and operation on the eventual costs of removal it is possible to modify the actions taken so that, at no increase in cost, the final cost of removal will be reduced.

To illustrate general lines of argument, specific examples are given. These are drawn from both the northern and southern sectors of the North Sea.
The Mechanism of Wettability Alteration Due to Surfactants in Oil-Based Muds
Authors: Menezes J. L. , Yan J. , Sharma M. M.
Published: December 2007

The mechanism for the alteration of sandstone wettability due to interaction with oil-based mud components such as cationic and anionic surfactants is investigated. Extensive use of such surfactants is made in drilling muds and completion fluids. It is shown through contact angle and capillary pressure experiments, that oil-based mud components can in some cases drastically alter the original wettability conditions of both sandstone and carbonate rocks. The wettability alterations are caused mainly by surfactants in the drilling fluids.

Contact angle measurements were made on quartz that had been equilibrated with the oil-based mud components. Additional measurements were made on quartz in the presence of an aqueous solution of the drilling fluid component.

The changes in the measured contact angles are explained on the basis of disjoining pressure concepts. The van der Waals, electrostatic, and structural components are considered. Zeta-potentials on the silica-surfactant solution and oil-surfactant solution interfaces are measured. Contact angles computed using the van der Waals and electrostatic components only are not in agreement with the experimentally measured angles. It is clearly shown that the structural component needs to be accounted for to calculate a theoretical angle that is comparable with the experimental angle. The structural component was found to vary with the concentration of surfactant presumably due to the formation of monolayer and bilayer structures. The results of this study provide a general framework within which wettability alterations caused by surfactants in drilling or completion fluids can be viewed.
Acidizing Fluids Used to Stimulate High Temperature Wells Can Be Inhibited Using Organic Chemicals
Authors: Frenier W. W.
Published: December 2007

In order to protect production tubing from corrosion during acidic stimulation treatments at temperatures above 250°F (121°C), inhibitors containing heavy metals (copper, arsenic or antimony) have been employed. These metallic inhibitors are the subject of increasing regulatory control in the US and abroad. A new inhibitor system containing only organic chemicals (ketones, quinolinium salts and formic acid) now has been developed to protect oilfield tubular goods to temperatures as high as 400°F (204°C) in hydrochloric acid.

This paper will describe the synthesis and testing of a series of pyridinium and quinolinium compounds used as part of an inhibitor package that also contains aromatic ketones and aliphatic acids such as formic acid. Using the corrosion rate of N80 steel as the major descriptor, Quantitative Structure-Activity Relationships (QUSAR) were constructed. Based on such relationships, the structure of the quat component was optimized, and an experimental formulation was devised. This Experimental High Temperature Acid Inhibitor (EXHTI) was then tested in a variety of acidizing fluids in contact with carbon and alloy steels at temperatures to 400°F (204°C).
Adsorption and Desorption Characteristics of Mineral Scale Inhibitors as Related to the Design of Squeeze Treatments
Authors: Przybylinski J. L.
Published: December 2007

Five structurally different scale inhibitors were studied using a kinetic adsorption-desorption technique. Adsorption was fast. All inhibitors adsorbed to a similar degree. Desorption was slow. There were large differences in the degree to which different inhibitors desorbed. The kinetic desorption characteristics are more important in picking an appropriate squeeze chemical than are the adsorption characteristics.

The study realistically modeled the flow rate, contact time and brine composition that might be found in an oilfield reservoir. Adsorption was measured on limestone at 40°C and sand at 40°C and 80°C. The inhibitors were diethylenetriamine pentamethylenephosphonic acid, hydroxyethylidene diphosphonic acid, a triethanolamine phosphate ester, a polyacrylic acid, and a polymeric phosphonate inhibitor.
Waterflood Performance Projection Using Classical Waterflood Models
Authors: Wu C. H.
Published: December 2007

A semi-empirical method is proposed to forecast waterflood performance using classical waterflood models. The approach adopts an average flood pattern for waterflood performance projection. The pattern waterflood performance was obtained by using a semi-empirical approach based on a comparison of the computed results from Buckley-Leverett-Welge, Dykstra-Parsons, and Craig-Geffen-Morse methods. The approach allows the engineers to adjust the effects of. dominant factors such as displacement mechanisms, vertical variation of horizontal permeabilities, mobility ratio, and areal sweep efficiency. The technique also allows for fillup of initial gas saturation which can be adjusted to match the response time. The field-wide waterflood performance is computed using the average pattern waterflood performance and a prescribed pattern development schedule. The technique can be used for initial waterflood project evaluation or for matching the performance of a matured waterflood. The approach is practical and helpful for reservoir engineers working on waterflood project evaluation and management.

The approach has many inherent limitations. There are numerous assumptions made in the Buckley-Leverett-Welge, Dykstra-Parson, and Craig-Geffen-Morse methods such as homogeneous reservoir layers with constant porosity, permeability, and initial saturation. The proposed approach does not provide individual well performance and does not give a unique answer to the waterflood performance forecast problem. Due to the inherent limitations, the reservoir engineers should exercise good reservoir engineering judgements when using the proposed waterflood calculation technique.

A field example is used to illustrate the steps for completing the waterflood performance projection. A package of personal computer programs could easily be developed to relieve reservoir engineers from repetitive and laborious calculations and aid in parametric sensitivity study.
Short Radius Drilling Technology Utilizing Mobile Service/Workover Rig
Authors: Keelean L. , Harris S. S. , Petronio N.
Published: December 2007

The paper will discuss a multi-well, short radius lateral drilling project in a gas producing shale formation in northern Michigan. A description of short radius drilling tools and associated equipment, and the mobile service rig and auxiliary equipment will be presented. Drilling and completion procedures including mobilization, de-mobilization, rig-up and rig-down will be summarized, along with graphical representations of time curves, cost curves and directional section profiles.

The benefits of packaging multiple services and how it may apply to establishment and development of a learning curve will be evaluated. Limitations of both the short radius lateral equipment, and the mobile service rig will be reviewed, along with available optional equipment that is compatible with both systems. The economics of utilizing a mobile service rig versus a conventional drilling rig will be discussed.
Experimental Study of Erosion in Diverter Systems Due to Sand Production
Authors: Bourgoyne A. T.
Published: December 2007

When drilling from a bottom supported structure, the best procedure for handling a threatened blowout from a shallow gas formation is to divert the gas flow away from the structure and drilling personnel. Case histories were reviewed in which failures occurred during diverter operations due to erosion caused by sand production. A model diverter system was constructed to evaluate this problem and provide information that can be used in the design of diverter systems. A number of pipe fittings used at bends in diverter systems were experimentally evaluated. The effect of flow velocity, liquid content, and sand concentration were included in the study.

It was found that very rapid wear can occur at velocities near sonic velocity. Wear rates of 8-in./hr were measured for short radius "Ells." The rate of erosion was found to be about two orders of magnitude higher for gas/sand mixtures than for liquid/sand mixtures. An equation was developed for predicting the wear rate for various field conditions. Recommendations are given for improving the erosion resistance of diverter systems.
The Transition Pressure: A Quick Method for Quantifying Polyacrylamide Gel Strength
Authors: Smith J. E.
Published: December 2007

Because of the large numbers of gel systems and field specific variables that affect gel strength, several gels must be tested to choose the right one for a given field application. An apparatus designed for quickly quantifying gel strength, called the TGU Apparatus, was designed for screening large numbers of gel systems. The TGU is a counterpart to the Screen Factor Apparatus which is used for testing polymers. Like the Screen Factor Apparatus, the TGU Apparatus has a screen pack, made up of five 100-mesh screens, through which the test solution is flowed. Unlike a Screen Factor test, pressure is applied to the solution to force it through the screens in a TGU test. By plotting flow rate against pressure, a Transition Pressure is obtained. The Transition Pressure is proportional to the strength of the gel and is used to compare gels quantitatively. It takes fifteen minutes of lab work to obtain a Transition Pressure for a gel.

In this paper, instructions are given for obtaining Transition Pressures for gels using the TGU Apparatus. An example of how the Transition Pressure was used to determine the best gel for a given field situation follows. Lastly, a correlation between Transition Pressure and gel performance in sand packs is presented.
New Options for Scaling Steam Injection Experiments
Authors: Kimber K. D. , Farouq Ali S. M.
Published: December 2007

Scaled model experiments are a valuable aid to steamflood design and simulation. They can also be an important adjunct to numerical simulators, when numerical simulators do not represent a recovery process adequately. Field data for history matching and data describing interaction between various components, additives, and porous media may not be readily available. Scaling techniques that are currently being used can also be limited, as they require porous media and pressure conditions different from those of the field being studied. Any properties dependent on pressure (e.g. PVT properties) or porous media (e.g. relative permeabilities) are not scaled accurately. New scaling criteria were developed which allow field porous media and pressure conditions to be used. Two of the new approaches achieve this in a novel manner by relaxing the requirements of geometric similarity. The advantages and disadvantages of each approach were investigated.

In order to compare the capabilities of the scaling approaches, experimental results from a large model were compared with those from smaller models which were scaled using each approach. The ability of each approach to predict such parameters as energy and temperature distribution, oil production rate, water-oil ratio, steam zone size and steam breakthrough are presented.

The scaling approaches which use field porous media and pressure conditions yielded results in agreement with those of an accepted high-pressure approach from the literature. The new approaches provide scaling options which should be better for steam processes which use additives (PVT properties must be scaled), processes which use pressure cycles (fluid compressibilities must be scaled), and processes in which it is essential to use the same porous media as found in the field.
Vertical Expansion of the 10-Pattern Steamflood, Kern River Field, California
Authors: Hajdu P. E. , Merrell J. M. , Sanford S. J.
Published: December 2007

In 1984 the 10-Pattern steamflood was expanded upward into two drive zones overlying the original steam-flooded sands. Neutron and temperature logs from new wells associated with the expansion project showed heating and unexpected liquid depletion in the target sands. This depletion resulted in low pressure and temperature steam zones forming in these sands. In the third year of the project a heating analysis using data from observation wells indicated that the drive zones were thermally mature at the low steam zone temperatures. As a result of the analysis, steam injection into one of the drive zones was changed to hot water and steam injection rate into the other, less mature, drive zone was reduced by 70 %.
Capacitance Water-Cut Probe Utilization in the Kern River Field
Authors: Hohn P. P. , Morton F. R.
Published: December 2007

Lower oil prices have increased the demand for accurate well gauging results in recent years. A primary component of the well gauging system is the water cut probe. At Texaco's Kern River thermal operation a quality assurance and preventive maintenance program has been successfully implemented. In its first - year this program has been useful in maintaining proper calibration of water cut probes and in identifying failures before they significantly affected well gauging results.