bluuebunny/crossref_metadata_2025 huggingface dataset:
A Petrophysical-Mechanlcal Math Model for Real-Time Wellsite Pore Pressure/Fracture Gradient Prediction
Authors: Holbrook P. W. , Hauck M. L.
Published: December 2007

Petrophysical-mechanical math modeling is an entirely new approach to Pore Pressure/Fracture Gradient prediction. Traditional petrophysical techniques are used to estimate rock porosity, (ϕ) and relative shale volume (Vshale). In this new methodology, pore pressure is calculated from earth stresses rather than empirical fluid pressure relationships.

Overburden stress is an integrated bulk density log derived from porosity, (ϕ) and Vshale. Effective vertical stress is calculated from porosity, (ϕ) for each lithology (Vshale) using the Rubey & Hubbert (1959) relationship. Pore Pressure is the difference between overburden and effective vertical stress, following the Terzaghi (1923) relationship. Fracture propagation pressure is the sum of effective horizontal stress and pore pressure. In relaxed sedimentary basins, effective horizontal stress is calculated from effective vertical stress for each lithology (Vshale). Visco-plastic rather than elastic rock properties are used to calculate effective horizontal stress.

This new methodology has been used on 17 wells in the Gulf of Mexico. Well planning is done by batch processing of log data. Drilling operations are supported by real-time processing of MWD log data at the wellsite. Accuracy has been better than 1/2 ppg where lithologic discrimination was good and stress modeling assumptions were met.
Estimation of Parameters for Drilling in Arctic and Offshore Environment in the Presence of Hydrates
Authors: Roadifer R. D. , Godbole S. P. , Kamath V. A.
Published: December 2007

The presence of gas hydrates in Arctic and subsea regions is well documented. Hydrate cores have been obtained from the Gulf of Mexico, the western coast of Guatemala, and in 1972, ARC0/EXX0N recovered a hydrate core sample near Prudhoe Bay, Alaska (Holder et al, 1984). In addition, hydrate deposits in the Canadian and Russian Arctic are known to exist (Makogon, 1965; Bily and Dick, 1974).

Irrespective of the location, drilling through hydrate formations can cause well control problems due to severe mud gasification if proper drilling procedures are not followed. Sizable gas kicks and potential blowout conditions have been reported in the literature (Davidson et al, 1978; Franklin, 1979). The potential for well control problems due to hydrates is expected to increase in the future as further exploratory drilling occurs in known or potential hydrate stability areas; e.g., drilling activities in offshore and onshore Alaska can significantly increase in the future when ANWR (Arctic National Wildlife Refuge) is opened for oil and gas leasing (OGJ, 1986A, B).

Currently, two different methods are used to drill through hydrate containing formations. Predominately, cool drilling fluid with higher mud weight at high circulation rates is used to slow or prevent hydrate dissociation in the formation. Panarctic Oils Ltd., alternatively, tries to promote the dissociation at early times while the drill pipe is in the hole by using low weight muds with proper degassing equipment at the surface (Franklin, 1980).

A thermal simulator developed earlier (Roadifer, et al, 1987) is modified to model the dissociation of hydrates under a wide range of drilling conditions. Major new features include the coupling of wellbore heat transfer and hydraulics with the hydrate dissociation model. Well configuration and makeup are user specified and included in the wellbore calculations. Either arctic or subsea locations and corresponding geothermal and pressure gradients may be specified. For arctic regions, the melting of permafrost may be modeled concurrently with the hydrate dissociation.

The results are presented in a series of nomograms and plots for both arctic and subsea hydrate locations. These nomograms can be used quickly and easily to determine drilling parameters required to keep hydrate dissociation within the limits of the surface gas equipment, or alternatively, given the drilling fluid parameters, design criteria for the surface equipment can be established.
A New Class of Filtration Control Polymers Offer Exceptional Electrolyte Tolerance
Authors: Clements W. R. , Jarrett M. A. , Morton E. K.
Published: December 2007

This paper describes a new polyanionic lignin (PAL) filtration control polymer. The material imparts filtration control to a wide variety of water base drilling fluids. It is very temperature stable and contaminant tolerant.

The chemistry and structure of this polymer is compared to existing filtration control materials. Laboratory data is presented to show a relative comparison of PAL to other common filtration control additives.

PAL has been used in South Texas, the Gulf of Mexico, Italy and the North Sea. Field applications and observations are discussed. This material has broad application in environmentally sensitive areas because of the absence of heavy metals including chrome. A combination of PAL and polymeric deflocculants can be formulated to give more cost effective systems than traditional lignite-lignosulfonate systems.
New Chemical Package Produces an Improved Shale Inhibitive Water-Based Drilling Fluid System
Authors: Wingrave J. A. , Kubena E. , Douty C. F. , Whitfill D. L. , Cords D. P.
Published: December 2007

Quantitative shale stability performance data based on a new testing procedure (Dynamic Pellet Test or DPT) were used to quantitatively rank the shale stability performance of over 30 chemical species. Shale stability performance of over 3500 aqueous solutions or muds on over 20 different shale or clay samples was done. The test results allowed the following four conclusions about shale stability induced by inorganic and polymeric chemicals to be drawn: –inorganics alone are inadequate,–potassium ion is significantly better than any other cation in shale stability performance,–hydrogen bonding polymers are most effective and,–high molecular weight polymers (up to the limit of solubility) are most effective.

From the results of this work, a particularly effective shale stabilizing additive package for aqueous muds was identified. The exceptional shale stabilizing performance of these chemical structures is based on a chemical synergism uncovered through DPT testing. Typical drilling fluid formulations and their laboratory properties will be discussed, including tests conducted on a heated/pressurized flow loop.
Flow Patterns Under a Tricone Bit Determined From Pulsed Wire Anemometry and Flow Visualization
Authors: White D. B. , Escudier M. P. , Gavignet A. H.
Published: December 2007

At present, the optimization of drilling hydraulics consists of selecting nozzle sizes that maximize either jet impact or hydraulic power at the nozzle, whilst ensuring that the flow rate is sufficient to transport cuttings to the surface. If this crude approach is to be improved upon, what is required is an understanding of the cleaning mechanism at the work face, i.e. the action of hydraulic forces on the crushed rock. Previous investigations of the problem have focussed on the measurement of the mean and fluctuating pressure field under the bit, and on the distribution of fluid velocities.

We report here measurements of the mean and fluctuating shear stresses on the surface under a 8 1/2 in. roller J jet bit for a number of different nozzle geometries. The shear-stress maps obtained are shown to be consistent with the results of surface flow visualisation performed for the same bit. For a given configuration, the flow patterns observed were independent of nozzle size, and the measured shear stresses scaled with the momentum flux (at the nozzle).

The values of shear stress measured are two orders of magnitude greater than that required to move a chip and suggest that it is an important mechanism for bit cleaning. In a two-nozzle configuration, a major stagnation region is found to be situated at, about 2/3 radius whereas in the three nozzle case the stagnation zone is at the center of the hole. Since the flow pattern rotates with the bit, in the two nozzle case the areas of low shear stress are immediately followed by high shear stress and this sequence may prevent the build up of cuttings. This suggests a possible explanation for the observation that two nozzles can lead to faster drilling rates than three.
Optimizing Journal Bearing Insert Bit Runs Using a Bearing Life Model
Authors: Doiron H. H. , Tompkins L. B. , Watts T.
Published: December 2007

Advances in journal bearing insert bit technology have yielded very versatile bits which can often be run cost effectively at weight-on-bit (WOB) and RPM combinations which exceed manufacturers' catalogue recommendations. Insert breakage rather than tooth wear is the primary cutting structure concern at high mechanical horsepower levels. Field experimentation yields data on allowable WOB and RPM to avoid insert breakage. Below these WOB and RPM restrictions, insert wear is negligible, so the remaining unknown in WOB and RPM optimization is bearing life. This paper presents a semi-empirical bearing life model for journal bearing bits and a method for field implementation which has been useful in predicting bit life for insert bits. The model expresses expected bearing life within a given formation and depth range as a function of WOB and RPM. The model is also suitable for predicting bearing life for bits run on downhole motors.

Data are presented to show statistical correlation of the bearing life model with actual field results. A method for using the model to select WOB and RPM to minimize cost-per-foot of bit runs is presented. A successful case history using the bearing life model to predict bit life on high WOB and RPM downhole motor runs is also presented.
Use of Torque Analysis To Determine Tricone Bit Bearing Failure
Authors: Peltier B. P. , Cooper G. A. , Curry D. A.
Published: December 2007

The early stages of roller cone bit bearing failure have been detected by using a moving window to analyse changes in torque and weight on bit. Choice of window width enables other effects, such as changes in rock properties, to be tuned out of the diagnosis.
Simulation of Compositional Flooding Using Third-Order Difference Techniques
Authors: Taggart I. J. , Pinczewski W. V.
Published: December 2007

Conventional compositional simulators based on low order discretization techniques introduce unacceptably high levels of numerical dispersion and anisotropies (grid orientation sensitivity) when applied to miscible or multicontact miscible displacement processes. A simple, uniformly third order finite-difference scheme is developed which successfully overcomes these problems. A novel modification to the leading truncation term allows solutions to be obtained which are insensitive to grid orientation without reducing the order of accuracy of the solution.

The high order schemes developed are applied to one-dimensional multicontact miscible displacements where they are shown to predict recoveries considerably different to those obtained with low order schemes. In two-dimensional miscible displacements the high order method is used to study the growth of viscous fingers and the effect of gravity segregation in the presence of strong compositional effects. Comparisons with results obtained using low order methods suggest that the high order scheme has the potential to significantly reduce the computational effort involved in compositional simulation.
The Effects of CO2 Flooding on Wettability of West Texas Dolomitic Formations
Authors: Potter G. F.
Published: December 2007

Reduced water injectivity after CO2 injection has frequently occurred in West Texas oil fields. One explanation proposed for this phenomena was a a change in rock wettability by the CO2 and crude oil miscible bank. This paper describes an experimental study to determine the effects of CO2 flooding on the wettability of West Texas dolomitic cores.

This study examined the relative permeability characteristics of fresh-state San Andres and Grayburg dolomite core samples before and after passing a crude oil/CO2 miscible front through the test core. Changes in the relative permeability characteristics were used to infer the effects of CO2 flooding on rock wettability. The cores chosen were intermediate oil wet, intermediate, and intermediate water wet. The results showed that the cores became slightly more water wet. However, this change in wettability was near the limit of statistical confidence. Some data suggests that the tendency to becoming water wet was cause by slight rock dissolution by the CO2 and brine. Some observations concerning the compatibility of brines used in laboratory core floods with dolomites containing anhydrite are discussed.
Existence of a Secondary Optimal Salinity in Microemulsion Systems
Authors: Mehmet C. S. , Fuseni A. B. , Al-Hashim H. S. , Menouar H.
Published: December 2007

The optimal salinity has become the most important criterion for structuring surfactants to maximize solubilization of oil and water in microemulsion systems. Laboratory corefloods have demonstrated that surfactant systems show maximum oil recovery at this optimal salinity which also corresponds to a minimum interfacial tension. However, many oil reservoirs exhibit high salinities over 200,000 ppm and temperatures above 90°C. Since most surfactants produce low optimal salinities, the interfacial tension under such severe conditions is expected to be rather high.

In this study, we have found the existence of a secondary optimal salinity which occurs, at a salinity higher than the primary optimal salinity (previously known as the optimal salinity). The presence of a secondary optimal salinity has been tested for ethoxylated sulfonates of varying ethoxylation (EO) number with an alkene and also with crude oil. For example, for EO=8 while the primary optimal salinity with dodecane at 90°C takes place at 8% salinity, the secondary optimal salinity occurs at 14% salinity. Increasing the EO number shifts both the primary and secondary optimal salinities indicating that the secondary optimal salinity is not an artifact. Moreover, the data obtained so far reveal that the secondary optimal salinity yields even lower interfacial tension. The mechanism governing this phenomenon is elucidated on the basis of partition coefficients, phase inversion temperature and infrared data.

These results in addition to their theoretical interest are expected to open new avenues in the design of surfactant formulations for high-salinity and high-temperature oil reservoirs.
Improving Waterflood Performance in Oil Reservoirs with Bottomwater
Authors: Islam M. R. , Ali S. M. Farouq
Published: December 2007

This research addresses the problem of waterflooding a medium gravity oil-bearing formation with a water leg, and offers recommendations for process selection. In many reservoirs the presence of a bottom water zone results in very poor areal and vertical sweep efficiencies. However, waterflooding still remains the most widely used oil recovery technique for these reservoirs. Waterflood performance in such reservoirs can be improved greatly with effective methods of partially plugging the bottom-water zone. Some of these methods were developed in this study with a large flow model, by using a series of mobility control agents.

Polymer, emulsion, biopolymer, air, silica gel and foam, in various slug sizes, were used as mobility control agents for waterflooding an oil saturated reservoir model with a bottom-water layer. More than 80 model experiments were conducted to study the effect of permeability contrast, water-oil layer thickness ratio, oil viscosity, slug size, etc. Also, a series of runs were conducted with an artificial barrier of different lengths. Oils of viscosities ranging from one to 200 mPa.s were used in the displacement tests. A qualitative comparison is made to show the relative merits of the various mobility control agents. The blocking mechanism for each mobility control agent is investigated in detail and a comparison is made. It is shown that the choice of one mobility control agent over others depends on variables such as permeability contrast, oil-water layer thickness ratio, oil viscosity, injection interval (as a function of time). The effect of slug size is discussed for various mobility control agents and an optimum slug size is proposed. It is shown that for polymer, emulsion, foam and silica gel the poorer the conventional waterflood performance is, the more efficient the mobility control agents are. For instance, in the case of bottom water zone as thick and permeable as the oil zone, only about 15% 10IP may be recovered by a waterflood, whereas by the use of polymer, emulsion, foam or silica gel as mobility control agent, as much as 70% of the IOIP may be recoverable.
Laboratory Evaluation of Foaming Additives Used to Improve Steam Efficiency
Authors: Robin M.
Published: December 2007

During steam injection operations, the sweep efficiency is detrimentally affected by gravity effects or reservoir heterogeneities. In order to increase the sweep efficiency, research is being done on combined steam and surfactant flooding, causing the generation of foam; this would plug off the preferential flow paths, reduce the gas mobility, and enable the steam to invade a larger portion of the reservoir.

A laboratory study was carried out to determine and follow the evolution of foamability from ambient conditions up to about 300°C and 10 MPa (572°F and 1450 psi), corresponding to high pressure steam injection. Foam efficiency was evaluated by displacement tests in porous media.

For most of the currently used surfactants, foam stability is dramatically affected by the presence of a residual oil phase. Moreover, the efficiency of foams decreases considerably when temperature increases.

Testing various surfactants in the presence of oil enabled us to screen some chemicals that form foams whose stability is not affected by the contact with a hydrocarbon phase. The pressure drop during foam injection is studied versus temperature and foam quality, in a homogeneous porous medium.

Blocking properties of foams generated by different surfactants are compared under various conditions.

Work has been done under laboratory conditions to visualize the mechanisms of foam action for increasing oil recovery, in cores which are either homogeneous or constist in two layers with different permeabilities. A considerable difference is noticed between the usual surfactants and certain chemicals which are not affected by the presence of oil.

It can be observed that foam stability decreases severely with rising temperature. This effect can be reduced by adding some appropriate compounds to the surfactant solution, prior to injection.

Results of displacement tests performed in cores with crude oils, under steamflood conditions, show a significant increase in recovery due to foam efficiency. These experiments were mainly conducted under isothermal conditions.
Simulation of Field Results of Cyclic Steam/Gas Injection in the Bolivar Coast, Western Venezuela
Authors: Salazar A. , Sánchez N. , Martínez C. , Colonomos P.
Published: December 2007

The injection of a small slug of natural gas immediately after the injection of steam, has been proposed as a method for improving the oil production of a cycle of steam stimulation. This approach is being tested by MARAVEN in an area traditionally exploited by cyclic steam injection.

Results of pilot tests of cyclic steam followed by gas injection in heavy oil reservoirs (9–12°API) in the Tía Juana and East Tía Juana Fields of the Bolivar Coast in Western Venezuela are presented. The tests in the Tía Juana Field were performed during a first cycle, with an increase of 20% in the oil production due to the gas injection. The tests in the East Tía Juana Field were performed during a fourth cycle, with no significant change in the oil recovery.

To understand the observed behavior and the merits of the gas-slug injection, the pilot tests were successfully simulated with a three-dimensional compositional thermal numerical model. In the East Tía Juana fields this involved simulating 36 years of production during depletion and the three cycles prior to the steam/gas stimulation. In the Tía Juana Field it involved only the steam/gas stimulation cycle.

To study the parameters that affect the recovery due to the injection of gas, a sensitivity study with varying gas injection conditions, and reservoir conditions at the start of the steam/gas stimulation was conducted. Results indicate that the extra production due to the injection of gas, is highly sensitive to the pressure of the reservoir at the start of the injection. This result confirms the observed field behavior.

The main mechanism responsible for the increase of production due to the injection of gas is solution gas-drive. This effect is more important at the higher pressures normally present during the first stimulation cycles. Other factors such as changes in saturations, pressure, and temperature are deemed to be of relatively minor importance.
A Field-Scale, Three-Dimensional Simulator for Thermal Oil Recovery
Authors: Dogru A. H. , Odeh A. S. , Jines W. R.
Published: December 2007

This paper describes a field-scale, three-dimensional thermal simulator, THERMS. THERMS is primarily used to design and predict the performance of steam flooding and in-situ combustion of oil. In addition, hot water or gas injection can be simulated. The model has been designed to handle large-scale thermal field projects. A novel numerical solution has been developed which allows THERMS to simultaneously simulate thermal pilots at different locations together with the remaining areas of the reservoir. This feature enables the model to properly account for the interaction between the pilot and its surroundings, which is necessary for reliable simulation results.

THERMS treats the burning front, in the in-situ combustion process, as a moving heat source. A special flow enhancement algorithm is used to maintain the fuel consumption at the laboratory measured value, if so desired. Detailed kinetics and thermodynamics relations are not treated. Thus, THERMS is best suited for in-situ combustion of heavy oil in contrast to light oil.

Numerically, THERMS' algorithm is strongly coupled and fully implicit which gives it the required stability to simulate difficult reservoir conditions. A nine-point finite difference formulation option significantly reduces the grid orientation effects. THERMS can run in a scalar or vector mode.
Simulation of a 12-Pattern Field Trial of Light Oil Steamflooding
Authors: Blunschi J. H.
Published: December 2007

As part of a field trial of light oil steamflooding in the Buena Vista Hills Field, California, a simulation study was undertaken using a compositional thermal simulator. The objectives of the study were to quantify the influence of reservoir heterogeneity on recovery and to predict size and location of a solvent bank during the field trial.

Two simulation models were constructed, consisting of a 4-component oil and detailed grid systems sufficient to describe the recovery processes. A 2300-cell, 4-layer model of 12 inverted five-spot patterns and one row of adjacent patterns surrounding the pilot allowed the study of the influence of heterogeneity on recovery. A 1900-cell, fractal model of 1/8 of a confined five-spot was used to examine the development of the solvent bank. Both models were history matched with the first 14 month of injection/production data from the pilot.

A high permeability zone and high pore volume compressibility were identified as major controls on recovery. Different arrival times of solvent banks at the producers and vertical trapping of oil makes the detection of solvent banks at the producers difficult. Prediction runs with the history matched model indicated a poor prospect for a hot water after steam flood.
Reservoir Description From Seismic Lithologic Modeling: Part 2—Substantiation by Reservoir Simulation
Authors: de Buyl M. , Ullah S. , Guidish T.
Published: December 2007

Two independently derived reservoir models of a stratigraphically complex oil field in Alberta, Canada, were used as the bases for reservoir simulation and history-matching. This study is an attempt to compare the applicability of each method for obtaining a reliable description of the reservoir.

As discussed in paper SPE 15505, the first reservoir model was based on log and core data from six producing and two dry wells drilled within a portion of the field on which a 3-D seismic survey had been acquired; the second reservoir model was developed by supplementing well data with petrophysical parameters derived from seismic lithologic modeling of the 3-D seismic reflection data.

Using structure and net porosity-thickness models developed by these two approaches at two different stages of the field development drilling, history-match calculations of water cut were made on each model using the limited reservoir production and pressure history available to date. The results suggest that the seismically enhanced reservoir model produces a more accurate simulation of the observed performance than that achieved with a "conventional" reservoir model based solely on well control. This observation is particularly true at earlier stages of development drilling when inadequate reservoir descriptions can be produced based on limited well control. This study supports the potential technical benefit of using 3-D seismic data to obtain an improved reservoir description and thereby, lead to improved design of field development and operational programs.
A Method for Pressure Buildup Analysis of Drillstem Tests
Authors: de Franca Correa A. C. , Ramey H. J.
Published: December 2007

Analysis of the pressure response obtained from a drill stem test (DST) provides important additional information for deciding whether it is economical to complete a well.

Interpretation of DST pressure buildup data has been based on the Horner method. The basic assumption of the Horner method is that the well is produced at a constant rate before the shut-in. When rate changes with time, a cumbersome application of the superposition principle is required to analyze the pressure buildup data.

Furthermore, the solution of the diffusivity equation for a constant production rate gives a declining flowing pressure with time, but most DST's show an increasing flowing pressure during production. Therefore, the application of the Horner method may lead to inconsistent results in the interpretation of DST pressure buildup data.

An original approach was used to model the DST problem. A DST can be characterized as a changing wellbore storage problem following an instantaneous pressure drop at the well. During production the wellbore storage coefficient is given by the rate of fluid accumulation inside the wellbore. After the shut-in of the well the wellbore storage mechanics change due to the compressibility of the fluid below the bottom hole valve. Therefore, using this concept, the flowing and the pressure buildup phases are modeled with a single inner boundary condition.

In this paper an analytical solution correct for both the flowing and shut-in periods was obtained by solving the diffusivity equation with a single inner boundary condition which included the mixed conditions for flow and buildup. Both a skin effect and wellbore storage were considered. Solution was obtained by Laplace transformation.

The solution was used to develop methods of interpretation for the pressure buildup period of drill stem tests. Application of these new methods of interpretation to DST field data may provide the initial reservoir pressure, the formation permeability and the skin effect. The interpretation methods are based on graphical analysis of the data and are easily applied in the field.

The interpretation methods are generalized to include multiple production-shut-in cycles, including step changes in the wellbore storage coefficient due to changes in the drill pipe diameter and/or due to variations in fluid properties.

Unlike the results obtained from the application of the Horner method, interpretation of field data using these new methods show excellent agreement between the parameters obtained from the analysis of the first and second shut-in periods of short term double-cycled DST's.

Field examples are presented.
Bright Lights on Petroleum Technology
Authors: Mills R. C.
Published: December 2007

The existing downturn in the oil and gas industry and uncertainties of future events demand the use of new and evolving technologies to more accurately identify prospects and economically develop the more remote, presently unproducible reserves. Inventiveness in solving exploration and development difficulties is not new to our industry but the less attractive, unstable market climate of today calls for imaginative approaches to conducting our business. The development and application of a wide array of sophisticated technologies will be the hallmarks of the successful companies in future decades.
Technical Personnel Development in a Period of Scarce Resources and High Uncertainty
Authors: Donohue D. A. T. , Lang K. R.
Published: December 2007

Now that the serious staff reductions have taken place and morale is beginning to return; and now that crude prices are still very uncertain, but we are gaining confidence that the oil industry will survive; it is time to consider the petroleum engineering training and development needs of the future. In this paper we begin with statistical information on the petroleum engineer, including recent changes in population and age distribution. Then, using the results of a questionnaire submitted by 17 operating oil companies, we summarize the expected increase in petroleum engineers in the period 1987-90, the key areas of training and development that are expected to be needed during the next three years, and the principal method of delivering such training. Finally, we comment on ways in which companies can achieve better performance from its engineers during periods of limited staff size and an uncertain economic environment.
Carbonated Waterflood Implementation and Its Impact on Material Performance in a Pilot Project
Authors: Blackford T. A.
Published: December 2007

Carbonated waterflooding is an enhanced oil recovery process developed in the early 1950's that may have potential application in several West Texas reservoirs. The process consists of saturating injection water with CO2 in order to swell the remaining oil-in-place, and thereby increase the amount of recoverable oil in a reservoir. The process usually involves less investment and CO2 demand than miscible CO2 flooding.

The effects of carbonated waterflooding on equipment material performance were monitored during a two well carbonated water injection pilot test conducted by Amoco Production Company in the Slaughter Field, Hockley County, Texas. Stainless steel and aluminum bronze material showed no deterioration during the test period. However, severe problems were encountered at holidays in the internal plastic coating of carbon steel pipe and fittings. Injection well material performance data and observations are presented to support these findings. In addition, the surface equipment design used to saturate injection water with CO2 will be presented. No attempt will be made to discuss the impact of carbonated waterflooding on injection well or reservoir performance.
Twenty-Seven Years After Grayson: Who Is Using Decision Analysis?
Authors: Williams J.
Published: December 2007

The petroleum drilling application of decision analysis is widespread in the petroleum literature. This article presents research showing that 27 years after it was introduced by Grayson, decision analysis is not widely used in practice.
The Perils of Market Value Averages
Authors: Diggle F. J. , David A.
Published: December 2007

Although knowledgeable purchasers buy oil and gas properties at a price to meet hurdle rates of return, there Is a great deal of Interest to both buyer and seller in what the current "market" is for the purchase or sale of properties. Measures of market value for oil and gas properties include such traditional yardsticks as dollar per barrel-oil-equivalent ($/B0E), risked present worth (PW), three year cumulative cash income, and present worth discounted at various rates.1 In this paper, we examine some of these yardsticks with a focus on actual figures. Additionally, the gap between prices that buyers are willing to pay for smaller and larger properties is examined.
Infill Drilling Economic Analysis of Carbonate Oil Reservoirs in West Texas
Authors: Laughlin B. A. , Jardon M. A. , Wu C. H.
Published: December 2007

This paper presents the results of an economic analysis of infill drilling in 16 carbonate oil reservoirs located in West Texas. The economic analysis included the evaluation of incremental waterflooding recovery over primary and infill drilling recovery over initial waterflooding.

Because of limited field and economic data available for this study, many assumptions were made to complete the economic evaluations. Two major cases of economic evaluation were performed: Case I used the past production and economic data to 1986 and the projection of these data from 1986 on to the assumed economic limit, and Case II used the past infill production data as if the projects were initiated in January 1986 and on to the assumed economic limit.

Results showed that about 68% of the infill drilling projects studied had an infill drilling incremental payout of less than two years with an incremental discounted cash flow rate of return greater than 20%. Only 3 7% of the projects studied had a waterflood incremental economics with the same criteria. Decreasing the well spacing generally decreased the infill drilling incremental payout and increased the incremental cash flow rate of return. As the OOIP/WS (well spacing) increased, the general trend showed an increasing infill drilling incremental net present value.

Results from Case II studies showed that for a $15/STB ($94/m3) oil price in 1986, about 68% of the infill drilling projects studied had an infill drilling incremental payout of less than two years with an incremental discounted cash flow rate of return greater than 20%. As the OOIP/WS increased, the general trend also showed an increasing infill drilling incremental net present value. When the oil price in 1986 was increased from $15/STB ($94/m3) to $25/STB ($157/m3), the increase in the incremental net present value (INPV) was substantial. For example, at a value of 20 for OOIP/WS (Means Field/San Andres), the INPV increased from $76 MM to $122 MM.
Numerical Simulation of Gas Drainage From Coal Seams
Authors: Spencer S. J. , Somers M. L. , Pinczewski W. V. , Doig I. D.
Published: December 2007

A rigorous two-phase, three dimensional numerical simulator for water and gas drainage from coal seams is presented. The coal seam is modelled as a duel porosity system in which the cleat is represented by a macropore or fractured network which allows two-phase flow of gas and water to degasification wells. Flow in this network is modelled in terms of Darcy's law with allowance for a Klinkenberg type correction for gas slippage. Both permeability and porosity may be specified as functions of seam stress.

A micropore network allows diffusion of gas desorbed from the coal matrix to enter the macropore system. The desorption process is modelled on the basis of equilibrium Langmuir isotherms and desorption rate is calculated from a numerical solution of a transient diffusion problem in characteristic microspheres. Comparison of the model with previously published models based on a simpler quasi-steady state assumption for the gas desorption process suggests that the quasi-steady state assumption is not generally applicable for simulation of coal seam drainage. The model is demonstrated to be a useful tool both in interpreting results from laboratory scale gas drainage experiments and in evaluating the performance of field scale drainage and gas production developments.
In-Situ Seismic Monitoring EOR: The Petrophysical Basis
Authors: Nur A. M. , Wang Z.
Published: December 2007

This paper presents laboratory experimental results on wave velocities in hydrocarbons, rocks and sands versus saturation, pore and confining pressures, temperature, and CO2 content. The results suggest that seismic, especially high resolution seismic methods can be used in detecting anomalous pore pressures, tracking thermal fronts and mapping high temperature regions in thermal EOR processes, and monitoring CO2 flooding and water flooding processes in reservoir insitu. However, much of the methodology and technology required still remains to be developed before routine field applications can be made.
Gullfaks Subsea Wells: An Operator's Implementation of a New Sand Production Prediction Model
Authors: Massie I. , Nygaard O. , Morita N.
Published: December 2007

Early studies concerning the sand producing tendencies of the Gullfaks reservoirs concluded that wells should be completed with sand control measures from the start of production. Results from a newly developed Computer Based Sand Production Prediction Model indicated that the Rannoch sands could be produced sand-free through natural completions. Specific guidelines must be followed in the design of the completion and also included in the reservoir management programme. The production phase of Gullfaks commenced with 4 subsea production and one subsea injection well, completed by selective perforation with high completion efficiency. The model prediction of no sand production has been confirmed by results from all wells after 6 months of production. This paper reviews the field implementation of the guidelines from the model for the 4 subsea wells completed in the Rannoch sands.
Hydraulically Fractured Gas Well Productivity Modeling
Authors: Nierode Dale E.
Published: December 2007

The validity and sensitivity of using a fracture geometry model in combination with a finite difference reservoir simulator for the analysis of fractured gas well productivity are examined in this paper. The validity of combining the Khristianovich-Zheltov1,2 fracture growth model with a single phase, gas reservoir simulator is established by comparing field data in low, moderate, and high permeability gas reservoirs with calculations. It is shown that all aspects of well behavior including drawdown, buildup, production flowmeter, core data, and finite reservoir size can be quantitatively modeled. The sensitivity, or uniqueness, of the fit to field data is demonstrated by computer-generated studies of a typical 2-dimensional-acting gas well, and by a similar analysis applied to one of the field data sets.

The paper contains a complete set of data for four wells that were fractured with eight fracture treatments. The data are in a form that can be readily used by anyone wishing to apply an alternative analysis. It is concluded from the evaluations in this paper that a 2-dimensional fracture shape model is adequate to quantitatively describe fracture dimensions for use in either long-term well productivity extrapolations or in optimal fracture treatment design.
Control of Microbiologically Influenced Corrosion in Oilfield Production Equipment
Authors: Littmann E. S.
Published: December 2007

Microbiologically influenced corrosion (MIC) is rapidly becoming one of the most researched areas of corrosion science.

Despite this research there have been relatively few case histories published where MIC was shown to be the major cause of corrosion in oil production equipment.

This case history describes a large oil producing system that once had an extensive history of no corrosion related problems in the production equipment. Shortly after a polymer flood was initiated, some wells began to encounter severe corrosion problems. Standard corrosion control programs were not successful in controlling the problem and laboratory analysis run on deposits strongly suggested MIC.

The corrosion related problems were finally controlled with a nonionic, nonsurface active biocide. The success of this product further validates the conclusion that the well failures were due to MIC.
A New Model for Studying Oilwell Pumping Installations
Authors: Chacin J. E. , Purcupile J. C.
Published: December 2007

A digital discrete model, similar to the analog model investigated by Midwest Research, has been developed to study pumpoff, pumping with anchored tubing, and gas interference downhole conditions. The calculated surface dynagraphs are presented for unanchored tubing, anchored tubing, 60% gas interference, 20 gas interference, and 80% pumpoff.

This model is similar to the analog model pioneered by Howe and Midwest Research. However, because it uses a digital simulation, a wide variety of downhole conditions can be modeled. The upper limit on the frequency of this model (which also applies to RP11L calculations) is also presented.
Compositional Two-Phase Vertical Lift Performance Modeling of Crude Oil and Retrograde Gas-Condensate Wells
Authors: Salisburg P. E. , Peden J. M.
Published: December 2007

Estimation has been made of the applicability and reliability of five well known oil well pressure drop prediction methods and for each method guidelines are presented concerning their accuracy as a function of flowrate, tubing size, liquid velocity, water cut and wellbore angle of deviation. New methods are presented for modelling pressure loss in retrograde gas-condensate wells. These methods employ redefined flow pattern map boundaries based upon the utilisation of available well test data and are superior in accuracy to existing multi-flow regime and no-flow regime, methods of interest. Fourteen crude oil compositions, five retrograde gas-condensate compositions and a total of 102 welltest pressure surveys from a wide range of North Sea fields are used to ascertain the suitability of the correlations. The fluid PVT properties are generated by the Peng Robinson equation of state and the Schmidt Wenzel equation of state is employed for improved liquid density predictions. Generally, the predictions compare most favourably with laboratory measured data. In addition, full consideration of transient heat-transfer to the formation is included in the modelling.
Gas Pulsation Analysis by Portable Computer
Authors: Davis B. J. , Whitman S. K.
Published: December 2007

Pipeline pulsation frequencies can be qualified, quantified, and recorded using a portable computer, an analog to digital converter board, and sophisticated commercial data acquisition and fourier transformation software, along with proprietary data manipulation programs. This newly developed hardware/software combination has many advantages over alternative pulsation detection systems, including the ability to record, on-site, the pulsation waveform for analysis used in designing attenuating acoustical filters. Case Histories illustrate the system's use.
Perforating the Horizontal Well: Designs and Techniques Prove Successful
Authors: Weirich J. B. , Zaleski T. E. , Mulcahy P. M.
Published: December 2007

The application of well servicing equipment to that of horizontal well completions present specific design considerations that do not arise in the norm of conventional well completions. Although tubing conveyed perforating has been most suited to highly deviated wells and long intervals, horizontal well designs must consider other factors. Short radius turns, long measured depths and extended pay intervals give rise to mechanical complications while running the guns, obtaining an underbalance, detonating the charges, and removing the guns from the well. Addressing reservoir characteristics by selecting perforation geometry and shot orientation is also an integral phase in the completion design. The judicious utilization and application of perforating equipment will result in the primary objective of optimum production.
Gravel Packing of Horizontal Wells
Authors: Dickinson W. , Anderson R. R. , Dickinson W. , Dykstra H.
Published: December 2007

One hundred percent gravel packing of horizontal wells has been demonstrated in the laboratory using bidirectional (two lift), water slurrified gravel packing. The first lift provides 70–90+% fill. A second, subsequent, reverse direction lift provides both 100% fill and consolidation. Deviation has been varied from 70° to 110°; the process is self-regulating.
Application of Type-Curve Techniques to Decline Analysis and Forecasting of Gas Wells
Authors: Harrington A. G. , Lee B. Y. Q. , Taylor P. S.
Published: December 2007

This paper presents a computer method for forecasting gas well performance and back calculating reserves using flow equations currently employed in well test/type curve analysis. Recent advances in well testing have allowed a greater understanding of reservoir properties and configuration early in the production life of a well. This knowledge can be used to directly estimate the future productivity through analytic procedures. The same techniques can also be employed to match production data and determine the original gas-in-place and reservoir configuration. The components of the empirical decline curve equations are thereby identified directly.

The usual limitations to type curve predictions caused by constant pressure, and constant rate assumptions or periods of shut-in are surmounted through use of superposition suggested by Carter and Tracy13. This enables the correct application to actual field cases where both pressure and rate decline throughout the production life. Flexibility exists to include linear reservoirs with eccentric well locations, low permeability, dual porosity, non Darcy flow and various wellbore conditions.
A Systematic Deliverability Analysis for the Hoadley Gas Condensate Field
Authors: Newbert J. D. , Trick M. D.
Published: December 2007

To maximize return on long term and short-term excess gas sales contracts and to minimize investment in field equipment, a producer must be able to quickly and accurately assess the deliverability of a gas field throughout its entire economic life. This paper outlines a systematic approach for predicting the deliverability of the Hoadley gas-condensate field. This paper illustrates procedures, applicable to any gas or gas-condensate field, for tuning the tank-type model to match historic data, and for performing deliverability forecasts.
Production Forecasting for Gas Wells Under Variable Conditions
Authors: Aminian K. , Ameri S. , Beg N. , Yost A. B.
Published: December 2007

Forecasting production rates from gas wells has always been of considerable importance to the natural gas industry. The conventional method to predict the performance of gas reservoirs requires data which are often unavailable. This is especially true for low permeability reservoirs. In the absence of complete reservoir data, production decline type curves are employed to predict future production rates utilizing past production data. The general assumption behind this technique is that the reservoir parameters such as drainage area, skin factor, etc., and operating conditions (back pressure) affecting gas production in the past will remain unchanged. There are, however, many occasions where it is necessary to forecast production rates under conditions which are not similar to those of the past.

This paper introduces a series of production decline type curves which can be utilized to forecast gas production rates under conditions which are different from those affecting well performance in the past. A gas reservoir model has been utilized to generate the type curves through changing the operating conditions and reservoir parameters. The model takes into account many factors which are usually ignored. These include the non-Darcy flow effects, skin factor, and pressure dependent gas properties.