bluuebunny/crossref_metadata_2025 huggingface dataset:
Russian Lateral (BKZ) Analysis
Authors: Wiltgen N. A. , Truman R. B.
Published: December 2007

This paper covers the essentials of the tools, and practice of basic Russian well logs and Russian log analysis techniques. Emphasis is placed on those tools used in Russia which are significantly different than their counterparts in other major petroleum producing provinces.

The BKZ Kapotax is five Russian lateral electrical resistivity logs run at different spacings depending on the reservoir thickness. It is used to calculate true formation resistivity. The technique corrects for mud and borehole effects using response curves modeled for a lateral log. This technique uses different tool spacings, borehole size, mud resistivities, diameter of invasion and the resistivities of the five laterals.

This paper presents the BKZ method for predicting the true formation resistivity from this combination of lateral logs. Laterals were the primary resistivity log recorded by Russians before the early 1980’s. Now the induction conductivity log is also being used, but not in the BKZ technique for determining Rt. Only lateral devices are used for this determination.

By using the BKZ method, quantitative information may be extracted from historically recorded data and allows improved evaluation of reservoirs in previously drilled wells.
Application of Siliciclastic Sequence Stratigraphy to Exploration: Examples From Frontier and Mature Basins
Authors: Bowen D. W. , Weimer Paul , Scott A. J.
Published: December 2007

The application of sequence stratigraphic concepts has led to both successes and failures in petroleum exploration. A broad spectrum of reservoir occurrences are predicted in siliciclastic sequence stratigraphic models. The most successful applications have been in turbidite systems (lowstand systems tract) and incised valley-fills (lowstand and transgressive systems tracts). We analyze one example from each of these depositional settings which helps point out the successes and limitations of sequence stratigraphy in exploration of both frontier and mature basins.

The first example is from the Lower Cretaceous turbidite systems of the Bredasdorp and Pletmos basins of offshore South Africa. Exploration in these basins by Soekor (Ltd.) Pty demonstrates the frontier exploration applications of sequence stratigraphy. Basin-floor fans and basin-floor channel fill targets had 30% (14 wells) success ratio, whereas slope fan and prograding complexes had only one success. Drilling in the adjacent Pletmos basin had no success in five wells that targeted lowstand turbidite systems.

The Pennsylvanian Morrow Formation of eastern Colorado is the second example analyzed and demonstrates the application of sequence stratigraphie concepts in a mature basin. This is an incised valley-fill play that produces from several different valley-fill systems. Of the 181 wells drilled along a single valley-fill trend, 41.4% of the wells penetrated the valley (75 wells), 19.3% of the wells found reservoir quality sandstone (35 wells), and 9 new fields were discovered (5% rate of success). Since 1985, when the play was interpreted as an incised valley-fill, drilling statistics indicate that there was no significant increase in the success rate of discoveries, even though a greater percentage of wells penetrated valley-fill facies. This case study indicates that the major problems in valley-fill exploration were 1) locating the valley, 2) locating reservoir sandstone within the valley, and 3) finding a trap for the reservoir.

These drilling results indicate that sequence stratigraphy helps in exploration by defining play boundaries and prospects. However, they also suggest that the application of sequence stratigraphie concepts may not directly result in an increase in the rate of success of individual prospects. Sequence stratigraphie analysis only addresses the reservoir, source, and seal components of the petroleum system. Trapping mechanisms still remain a significant source of risk.
Fanlobe Geometry and Reservoir Sand Characteristics of Ram/Powell Field, Deepwater Gulf of Mexico
Authors: Clemenceau G. R. , Miller P. L.
Published: December 2007

Ram/Powell is one of the largest Deepwater Gulf fields discovered to date. The geologic model describing this field is based upon an interpretation of well, core and 3-D seismic data. The reservoirs are trapped within the turbidite sands of a Miocene deep-sea-fan. This fan is composed of multiple fanlobes which have seismic reflectors of varying amplitude and internal/external configuration. Individual fan lobes have elongate lens-shaped geometries which pinch-out updip and laterally, forming a stratigraphic trap. Amplitude and isopach maps display sinuous trends, sub-parallel to lobe axes, which are interpreted as turbidite channel/levee deposits. Sands associated with these channels are massive and have excellent reservoir characteristics. Thin-bedded levee/overbank turbidites encountered contain good quality reservoir sands.
Numerical Simulations of How Cap-Rock Properties Can Control Differential Entrapment of Oil
Authors: Rostron B. J.
Published: December 2007

The theory of differential entrapment of hydrocarbons, proposed by Gussow almost 40 years ago, has been used to explain the basin-wide distribution of oil and gas in reef trends. However, reef trends with hydrocarbon distributions different from the predicted distributions can be found. To date, there are no widely accepted explanations for these differences. In order to explain these discrepancies and better understand differential entrapment, a series of numerical simulations of oil migration in a reef trend were conducted.

Results show that the hydraulic properties of the system control oil migration and entrapment. If the cap-rocks are assumed to be impermeable (consistent with the original theory), then the spill point controls the height of oil column in the trap, and the position of the trap within the trend controls the type of hydrocarbon present. If the cap-rocks have some permeability, then entrapment is controlled by the interaction of the "sealing" properties (capillary pressure curves and permeability distribution) and the "leaking" properties (fluid density and formation-fluid gradients) of the system. Simulations illustrate that with certain cap-rocks it is possible to have traps that cannot be filled to their spill points.

A better match could be obtained between observed and predicted distributions of hydrocarbons for the entire trend if the model of differential entrapment is expanded to include the cap-rock properties of each reef.
Pressure-Transient Analysis for a Well With Multiple Horizontal Sections
Authors: Kamal M. M. , Buhidma I. M. , Smith S. A. , Jones W. R.
Published: December 2007

Available pressure transient solutions assume that the entire horizontal well section is contributing to flow. Analysis of transient tests using these models result in unrealistic values for permeabilities and skin. Production logging of such wells also indicates that only certain intervals are productive. This is probably the result of heterogeneity (e.g. the presence of fracture swarms) or damage. To solve this problem, engineers use an effective horizontal well length which is shorter than the actual horizontal well section. This however, does not reflect the actual flow configuration, since it assumes that the effective length is a contiguous section.

In this paper we show the effects of using too long a production interval on the interpretation of test data by analyzing numerically simulated tests from wells that are only partially open to flow in the horizontal section. We show how the values of horizontal permeabilities, vertical permeability, and skin are affected. We then present an analytical solution that allows for a well to consist of a number of segments of arbitrary length, strength, and skin. We use this model to document the effect of neglecting the actual flux distribution and well length on the results of the well test interpretation. A new radial flow regime is identified from the results of the segmented horizontal well model. It results in a flat pressure derivative at a value of 0.5 divided by the number of producing segments. We also use this model to analyze actual cases where pressure transient and production logging are available. This analytical model is also useful in handling dual lateral completions.

We show that the use of incorrect horizontal well length or flux distribution can lead to estimating erroneous well and reservoir parameters from pressure transient tests. We show actual production logging data that demonstrate the variation of the contribution from different sections of the horizontal well. The model presented in this paper enables the engineer to combine production logging data, or any other information that indicate the possible distribution of flow in a horizontal well, and pressure transient data to obtain more realistic well and reservoir parameters.
Use of Porosity as a Strength Indicator for Sand Production Evaluation
Authors: Sarda J-P. , Kessler Nicolas , Wicquart Emmanuelle , Hannaford Kevin , Deflandre J-P.
Published: December 2007

Production history, fluid pressure and uniaxial compressive strength are basic data to evaluate the risk of sand production. Evaluations of the compressive strength based on logs are illustrated for the example of a well on the Germigny-sous-Coulombs structure. Then relationships between compressive strength and porosity are developed using a theoretical approach of grain contacts, the analysis of published rock mechanics data and mechanical measurements on plugs taken from well cores. It is shown that compaction factor can complement porosity in the analysis. A field example illustrates the relationship between a critical differential pressure and compaction factor or porosity.
Determination of Reservoir Permeability Distributions from Pressure Buildup Data
Authors: Feitosa G. S. , Thompson L. G. , Reynolds A. C.
Published: December 2007

This work focuses on the analysis of pressure buildup data obtained at a well at the center of a cylindrical reservoir in which the absolute permeability is a function of distance from the well, i.e., is a function of the radial coordinate. It is shown that the permeability distribution can be estimated directly from pressure buildup data by application of an inverse solution algorithm. For cases where permeability is a function of both r and θ, it is shown that our inverse solution procedure yields an "equivalent" radial permeability distribution. It is also shown that the reservoir pressure profile at the instant of shut-in can be approximated from the buildup pressure data.

Finally, we discuss briefly, the stabilized inflow performance relations for a well producing from the center of a cylindrical heterogeneous reservoir.
Well Test Interpretation in Geologically Complex Channelized Reservoirs
Authors: Massonnat G. J. , Norris R. J. , Chalmette J. -C.
Published: December 2007

The interpretation of pressure transients by the use of analytical models generally leads to a simplified description of the geological heterogeneities around the well. Although this approach works when the geology is simple, clearly, more complex geological environments will prove difficult to analyse.

In channelized systems, such as alluvial and deep sea fans, the reservoir geometry may be poorly represented by simplistic geometrical arrangements that exist in the current analytical models. For example, the calculation of the distance to the no-flow boundaries is disturbed by the presence of levees. This aspect of the problem is clearly important as such calculations lead to an estimation of channel width, which may later be used as an input parameter for stochastic modelling.

Results of flow simulations of well tests from such complex geometries are presented in this paper. Using finely-gridded models generated from outcrop description and stochastic modelling, the influence of different geological parameters on pressure response is evaluated.

The study is performed in four steps. Firstly, a field example is used to define the problem: a pressure transient test is interpreted in terms of complex geology by the use of a combination of analytical solutions. Secondly, a known reservoir geometry (from outcrop study) is input into a well-test flow simulation model. Thirdly, a more complex reservoir is generated by stochastic (Boolean) techniques which is also simulated as in step 2. Fourthly, a new analytical solution allows for the correct interpretation of the original field example.

When reservoirs are characterized by channel type features, and particularly stacked channels, the no-flow boundaries identified on the derivative curve represent the limits of the system, rather than the limits of individual features. When channels are connected by levees, the levees influence the calculation of the distance to no-flow boundaries. The presence of levees increases the apparent channel width. All well-test interpretation results must be checked by comparison with the best available geological description of the sedimentary environment before quantitative data are supplied for geostatistical modelling.
Stress Sensitivity of Low-Permeability Sandstones From the Rotliegendes Sandstone
Authors: Farquhar R. A. , Smart B. G. D. , Todd A. C. , Tompkins D. E. , Tweedie A. J.
Published: December 2007

Rotliegendes sandstones have been found to display a wide range of petrophysical and mechanical properties stress sensitivity behaviour. The extent of stress related changes has been found for permeability, electrical conductivity and Young’s modulus to be related by the depositional facies. It has also been noted that the relationship between some rock properties which are thought to exist in situ can not be replicated unless measurements conducted at near in situ stress levels are employed. These results lead to the conclusion that the structure reflected by properties measured at low confining pressures is not representative of that which exists in situ.
On Perforating and Fracturing of Deviated Cased Wellbores
Authors: Yew C. H. , Mear M. E. , Chang C. C. , Zhang X. C.
Published: December 2007

The growth and link-up of mini-crack initiated at perforated holes from a deviated cased wellbore were studied by analyzing the behavior of cracks in the tangent plane of the borehole. Muskhelishvili's complex potential functions were used to construct the Green's function, which related the fracture opening displacements and external loads, for computational analysis of the problem.

It was demonstrated that, at a small perforation spacing, the mini-cracks from the perforated holes will link-up forming a large fracture along the wellbore. For cased wellbores, however, the fracture opening surface is not a smooth surface and there are large amount of rock masses entrapped by the connecting cracks. A rough fracture opening area and the entrapped rock masses might be the reason for the reported high friction loss in several deviated cased wells. It was also demonstrated that the situation could be greatly improved when the wellbore was fractured at a pressure which is much higher than the breakdown pressure.
Description of a Large, High-Pressure Slot Flow Apparatus for Characterizing Fracturing Fluids
Authors: Rein R. G. , Lord D. L. , Shah S. N.
Published: December 2007

A large slot flow apparatus for investigating hydraulic-fracturing fluid flow and proppant transport phenomena has been installed at the University of Oklahoma. The apparatus weighs 38 tons, has an adjustable width flow channel that is 9.3 ft long by 7 ft high, and includes capabilities for investigating leakoff phenomena and observing proppant transport. Operating conditions are pressures to 1200 psi and temperatures to 250°F. Initial tests, with a Newtonian fluid and with a 60 lb/Mgal hydrox-ypropyl guar (HPG) solution, show that all aspects of the apparatus and associated instrumentation needed to characterize the flow behavior of these fluids are working satisfactorily.
Field Application and Results of Pipe Tripping Nomographs
Authors: Bazer Donald A. , Owens Harry B.
Published: December 2007

Operational problems associated with tripping drill pipe or running casing become more severe and complicated as drilled holes get deeper and smaller. To reduce the many calculations required, primarily by the men on the rigs, nomographs were developed for solving annular, hole and pipe capacities and displacement volumes. A set of simplified nomographs were also developed, from previously published formulas, which can be used to estimate swab or surge pressures generated when annulus displacement mud flow is laminar. Examples of the use and accuracy of the nomographs are presented. The field results of using these presented. The field results of using these nomographs are mostly in the form of trouble free pipe trips, but some interesting and informative pipe trips, but some interesting and informative field results are presented.

Introduction

The swab and surge pressures generated while tripping pipe, become more critical as wells are drilled deeper and holes get smaller. If abnormal formation pore pressures are encountered which approach the formation fracture pressures, the problem becomes even more pressures, the problem becomes even more critical.

Induced swab or surge pressures while tripping out or into a hole cannot be eliminated but can be reduced to safe values. The most critical conditions exist when the mud hydrostatic pressure is very close to either the formation pore or fracture pressure.

Several methods for predicting swab and surge pressures while tripping pipe have been published. The mathematical methods, published. The mathematical methods, which have been proven to the most accurate by actual test, were found to be too involved and laborious for use by field personnel. The graphical methods found in the literature did not cover all ranges of mud properties and pipe-hole size combinations, and therefore pipe-hole size combinations, and therefore were deemed inadequate for field use. Using the proven mathematical methods developed by J. A. Burkhardt, nomographs were developed and are included in this paper. The nomographs have been in use for approximately one and one-half years and have proven to be reliable. Also included are nomographs for displacement volumes of drill pipe and collars, and annular or hole capacities developed as additional aids for the man on the rig to use in conjunction with tripping pipe.
An Overview of Current Acid Fracturing Technology with Recent Implications for Emulsified Acids
Authors: Li Yan , Sullivan R. B. , Rozieres Jean de , Gaz G. L. , Hinkel J. J.
Published: December 2007

The current acid-reaction testing methods for determining mass transfer and kinetics parameters are reviewed. Published acid fracturing models used in the industry are compared in terms of the basic equations, boundary conditions, solution methods and mass transfer considerations.

A sensitivity study (using a surface concentration model) shows the mass transfer coefficient to be the most important parameter which affects the shape of the concentration profile. The current industry standard correlation (Williams-Nierode) for determining the mixing coefficient is compared to laboratory results from history matching to determine the effective mixing coefficient for both Newtonian and non-Newtonian fluids. The laboratory results in the domain investigated (Reynolds numbers from 1 to 100) are generally lower than the Williams-Nierode correlation.

A quality control procedure for obtaining repeatable results from the rotating disk test is presented. This technique is also applied to power law fluids.

An emulsified acid field example is also presented to show the effectiveness of acid fracturing as a viable alternative to proppant fracturing.
Acheson D-3A Pool: Primary to Secondary HCMF—40 Years of Performance
Authors: MacLean D. A. , Edwards K. A.
Published: December 2007

This paper describes the development and performance of the Acheson D-3A pool from discovery through three depletion mechanisms over a 40 year period.

Discovered in 1950, the Acheson D-3A pool is a Devonian-aged dolomotized reef containing both vuggy and matrix porosity averaging 11.4% field-wide. Excellent reservoir performance results from horizontal permeabilities generally greater than one Darcy, and vertical permeabilities two to three orders of magnitude smaller than the horizontal permeability.

The development of the pool is traced from discovery through delineation drilling with emphasis on the type and quality of log and core data obtained, six years of primary production, followed by a gravity stable vertical waterflood, and, 30 years later, the design and implementation of a gravity stable secondary hydrocarbon miscible flood HCMF.

The secondary hydrocarbon miscible flood extension was initiated due to the success of the waterflood, experience from other operated vertical HCMF’s, and available royalty incentives. Design of the multi-contact miscible solvent slug and strategic production plans are described and compared to actual performance.

Better than expected performance of the secondary miscible flood lead to the further development of a full field tertiary miscible flood. The tertiary flood is described in the companion paper by K. A. Edwards and D. A. MacLean.1
The Design, Implementation, and Early Performance of the Acheson Tertiary HCMF
Authors: Edwards K. A. , MacLean D. A.
Published: December 2007

This paper describes the design of a full-field vertical tertiary hydrocarbon miscible flood (HCMF) in the Acheson D-3A pool. Subsequent design changes based on secondary HCMF performance, and early production history are presented. Monitoring and operation of the HCMF are also discussed.

The Acheson tertiary HCMF is unique in that there was no secondary production component in most of the tertiary miscible flood area. Two years of solvent injection, beginning in late 1990, were required to mobilize waterflood residual oil and generate an oil bank before production could begin. The original design, based on early performance from the secondary HCMF, called for a 10% hydrocarbon pore volume (HCPV) solvent slug followed by chase gas. However, later secondary HCMF performance indicated these design criteria were too optimistic.

Estimates suggested that an increased solvent slug size of 16–45% HCPV would be required. However, such a large slug requirement could jeopardize the economics of the flood. In order to minimize the size of solvent bank required, a solvent cycling strategy was adopted in which a solvent composed almost entirely of ethanes plus is injected into the solvent bank to replace and supplement produced solvent.

Two simulation models were used to design the cycling scheme, and develop the operating and monitoring strategies. One was a full-field cross-sectional model, and the other a detailed geostatistical cross-sectional model. They proved invaluable in understanding the mechanics of the displacement process and designing the solvent cycling scheme.
Horizontal Well Evaluation After 12 Years
Authors: Coffin Philippe
Published: December 2007

The paper presents a survey of 82 horizontal wells drilled between 1980 and 1992.

The survey includes 50 wells operated by ElfAquitaine during this period, plus 32 wells operated by partners. It covers more than 20 reservoirs in 13 different countries, onshore and offshore.

From the data base generated by the survey, statistical analyses are performed on the type of application, reservoir data, drilling and completion methods. The results are discussed.

Production performance and well costs are evaluated and compared to those of conventional wells.

Finally, the paper addresses successes and failures, and their causes. A rate of success is evaluated.
WAG Process Optimization in the Rangely CO2 Miscible Flood
Authors: Attanucci Vincent , Aslesen K. S. , Hejl K. A. , Wright C. A.
Published: December 2007

A miscible CO2 project was initiated in the Rangely Weber Sand Unit in northwest Colorado in 1986. Over the past seven years, the project has expanded areally to include 80% of the Unit, and substantial investments have been completed in injection, production and gas recompression facilities. As the project matures, emphasis has shifted from adding new CO2 injection patterns to management of CO2 injection, with goals of maximizing recovery and reducing operating costs. Optimization of the Water-Alternating-Gas (WAG) injection process is an important part of this effort.

Our initial injection strategy was based on reservoir simulation studies. It became apparent as the project matured that we would need to make changes in WAG processes to adapt to operational constraints and maximize pattern economics. Flood performance was optimized through further simulation and field testing of changes to CO2 slug size and WAG ratio tapering sequence. New methods for managing the WAG process based on injection pattern performance and economic triggers have been adopted. We have completed an initial comparison of predicted versus actual performance for injection patterns with tapered WAG ratios.

Simulation studies and field tests have also been completed to determine an optimum half-cycle for the WAG process in Rangely. A half cycle is defined as the amount of CO2 or water that is injected, measured in pattern hydrocarbon pore volumes, before switching to the alternate fluid. Our simulation and pilot project results have shown that decreasing the half-cycle has favorable economics. Results of the pilot have also demonstrated that production and fluid handling costs can be reduced by controlling fluctuations in gas and water production. Future plans for WAG optimization include continuation of performance monitoring to help optimize tapering strategy, and extension of the reduced half-cycle application to include simultaneous injection of CO2 and water.
Lost Hills Diatomite Simulation Study: Predicting Waterflood Performance in a Low-Permeability, Compacting Reservoir
Authors: Fast R. E. , Murer A. S. , Zambrano L. G.
Published: December 2007

A numerical simulation model was developed to predict waterflood performance and guide reservoir management in a low permeability, highly compactive opal-A diatomite reservoir. The 3-D model incorporates 23 reservoir layers and three rock types. Each rock type has unique, laboratory-measured compaction and relative permeability characteristics. Hydraulic fractures, dual-porosity, and dual-permeability features are incorporated. The model was validated by history matching and compared to field performance. Predicted results have been confirmed by the ongoing response to waterflooding. Reservoir description, model design, history matching, and prediction sensitivities are presented.
Measurement of Inflow Performance Parameters for Coal Seam and Devonian Shale Gas Reservoirs and Its Implication in Numerical Reservoir Simulation
Authors: King G. R.
Published: December 2007

This paper describes potential inconsistencies between the traditional methods used to estimate inflow performance parameters for conventional gas reservoirs and the way these parameters are used in analysing coal seam and Devonian shale gas reservoirs, particularly in numerical reservoir studies. These inconsistencies arise because of the unique reservoir characteristics and mechanisms associated with unconventional gas reservoirs.

For unconventional gas reservoirs undergoing non-equilibrium (dual-porosity) desorption, inflow performance parameters measured from deliverability tests may not be appropriate for numerical reservoir simulation. This is because the static pressures used in deliverability testing are influenced by the effects of pressure depletion in the fractures (during flowing conditions) and blow-down from the rock matrix (during shut-in). Under flowing conditions, the inflow performance in numerical reservoir simulators is governed solely by the cleat (fracture) pressure of the grid block.

Consequently, if a non-equilibrium desorption formulation is used in the simulation study, then the use of inflow performance parameters derived by deliverability testing may yield erroneous results.

The inconsistencies and analysis techniques discussed in this paper are applicable for all reservoir studies involving the inflow performance from unconventional gas reservoirs (analytical or numerical), however, they are more critical for numerical studies. These techniques are believed to be useful for understanding the need for representative inflow performance parameters for unconventional gas reservoirs.
Modeling the Effect of Subseismic Faults on Gas/Oil Displacement in the Upstructure Region of the Prudhoe Bay Field, Alaska
Authors: Angert P. F. , Bevan T. G. , Heffer K. J. , Pearce A. J.
Published: December 2007

Advances in the area of statistics / geostatistics, has allowed the estimation and subsequent object based modeling of the occurrence and spatial relationship of sub seismic faults in the upstructure area of the Prudhoe Bay Field. Statistical techniques assume that a power-law relationship can be used to determine the number of sub seismic faults of a particular length that exist within a given area.

Subsequent numerical gas / oil fluid flow simulation through realizations of this portion of the reservoir with and without sub seismic faults represented has revealed the significant impact faults with throws less than seismic resolution have on fluid flow. An analysis of individual historical / predicted well GOR performance supports the conclusions about the effect of sub seismic faults.

In the interwell region, sub seismic faults in the upstructure area of the Prudhoe Bay Field mitigate the magnitude and frequency of gas under running continuous and discontinuous shales by breaching thinner shales. This allows a path by which gas may migrate upwards toward the current GOC.

In the near wellbore region, breaching of continuous / discontinuous shales by sub seismic faults results in an increased potential for gas coning, due to a higher effective Kv/Kh ratio.

Explicit modeling of continuous / discontinuous shale distributions within the upstructure area of the Prudhoe Bay Reservoir without inclusion of the effect of sub seismic faults results in an inability of numerical fluid flow simulation to even come close to matching past historical production performance.

Techniques utilized and the methodologies described, allow the evaluation of the effect of sub seismic faults in fluvial depositional environments that can be characterized by sandstone matrix interbedded with large continuous and discontinuous shales.
Application of Variable Formation Compressibility for Improved Reservoir Analysis
Authors: Yale D. P. , Nabor G. W. , Russell J. A. , Pham H. D. , Yousef Mohamed
Published: December 2007

Formation compressibility has long been recognized as an important factor influencing production behavior from overpressured oil and gas reservoirs. However, formation compressibility data are not routinely collected and the use of formation compressibility in reservoir analysis and simulation is often oversimplified.

This paper discusses more accurate methods to determine formation compressibility and introduces a new method for analyzing overpressured oil and gas reservoirs which utilizes the variability of formation compressibility with declining reservoir pressure. The newly developed method departs from earlier proposed methods in the use of variable rather than fixed formation compressibility by employing a "pore volume formation volume factor", Bf, that properly integrates pore volume compressibility effects over the full pressure range of investigation. Using the new concept of Bf, the material balance equation (MBE) can be modified to include the effects of pressure dependent formation compressibility.

We find that the formation compressibility in highly overpressured unconsolidated reservoirs can be the same order of magnitude as gas compressibility and significantly higher than oil compressibility. In some types of reservoirs, an order of magnitude change in formation compressibility can occur during drawdown. We show that in many overpressured and/or unconsolidated reservoirs, proper integration of accurate formation compressibilities is important for reserve estimates, determination of drive energies, and overall reservoir development plans. For example, we find that the use of compressibility values in the MBE which are significantly lower than those which exist in the reservoir could suggest a strong water drive where one does not exist.
Critical Gas Saturation: Modeling and Sensitivity Studies
Authors: Li Xuehai , Yortsos Y. C.
Published: December 2007

The critical gas saturation (Sgc) is an important parameter in solution gas-drive processes. Despite considerable amount of research, however, both the concept and its values in various porous media remain unclear and a cause of confusion in the literature. Based on various definitions, values as low as 1% and as high as 27% have been reported. In this paper we present an investigation on the fundamental aspects of bubble growth and the formation of critical gas saturation in porous media. A theoretical model is developed, based on which a pore network simulator is constructed. We discuss patterns and rates of growth for single and multiple gas clusters, using statistical models, such as percolation and DLA. It is shown that in porous media, gas evolution (patterns and rates) are much different than in the bulk. The critical gas saturation is studied in terms of the system parameters, notably the nucleation fraction and the pressure decline rate. Sgc is found to be increasing with the nucleation fraction and the pressure decline rate at relatively high rates, but to be independent of the latter at sufficiently small rates. A condition for this is developed. The scaling up with system size is also discussed.
Future Performance Prediction for Water Drive Gas Reservoirs
Authors: Layne M. A. , Numbere D. T. , Koederitz L. F.
Published: December 2007

The development and application of a Boundary Element model for the prediction of gas reservoir performance under water drive conditions is presented. The model retains the natural coupling of the gas reservoir with the aquifer and treats them as a two-region composite system. The diffusivity equation is written separately for each region and each is converted to a Boundary Integral equation. The two resulting equations ( non-linear for the gas reservoir and linear for the aquifer) are linked by the compatibility and continuity conditions on the gas/water interface boundary separating the two media. A modification of the Powell hybrid method was used to solve the final combined non-linear matrix.

Output from the model include predictions of the pressures along the reservoir aquifer interface or gas-water-contact (GWC), the average pressure in the gas reservoir, and the average aquifer pressure.

These are plotted and presented as functions of time. These plots can aid analytical predictions of gas reservoir performance using the Material Balance Method.

The model is validated by comparing its results with those using a finite difference simulator. The results show comparable accuracy with finite difference models but with less data input. This is a useful model for areally large and arbitrarily shaped systems such as reservoir/aquifer composites because it has less data requirements than conventional numerical models.
Predicted Increase in Gullfaks H2S Production Associated With Injected Sea Water -- Application of Biofilm Model
Authors: Tyrie J. J. , Ljosland E.
Published: December 2007

H2S was found to be Increasing in Gullfaks produced sea water. Wells supported by the same injector showed similar development indicating an association between the injector and the H2S. Statoil's biofilm model was used to history match this behaviour to set the input parameters and enable a prediction to be made for each well. Some wells will exceed the process H2S limits and solutions are discussed. Produced water re-injection was shown to be detrimental to souring reservoirs.
Conversion of a Semisubmersible Drilling Unit for Tender-Assisted and Conventional Drilling Operations
Authors: Spiers R. L. , Tranter P. H. , Burr G. R. , Unsworth M. I.
Published: December 2007

The economics of marginal field development in the UKCS can be made much more attractive by reducing capital investment costs in drilling equipment, platform equipment, and jacket structure sizing and construction. This can be achieved through the introduction of semi-submersible Tender Assisted Drilling (TAD) techniques. The classical approach to TAD requires the use of a standard flat floating barge in support of a small jacket mounted drilling package. This technique cannot be used in the severe environmental conditions of the North Sea, but the viable alternative of using a modified semi-submersible drilling unit has been identified and more recently put into place.

An international drilling company, under contract to a major North Sea operator, has modified a Sedco 700 series design semi-submersible drilling unit (Sedco 704) to perform drilling operations in both TAD and conventional stand alone drilling mode for a UKCS development project. The planning, design, modifications, and performance tests were completed within the contract schedule and budget cost and the unit was delivered ready for platform hook-up and drilling operations in December 1992.

This paper discusses the philosophy behind the selection of the unit, the studies associated with the complicated mooring requirements, and the modifications made to allow for operations in TAD or stand alone drilling mode. Solutions to interfacing problems with the transfer of power, drilling fluids, and personnel between the unit and the jacket are also described and discussed.
Produced Brine Underground Disposal Injection Cost Model
Authors: Weller T. F.
Published: December 2007

Key components in the economic evaluation of either production or development prospects are the capital requirements and operating costs of a brine disposal system. Many times, emphasis and attention are given solely to the potential and resulting cash flow from production. Proper planning requires that consideration be given to producing costs. A key component of producing costs is the cost of operating a brine disposal system and the required capital investment.

Several Issues must be addressed in order to gain an understanding of the true cost of brine disposal. Generally, in the oil and gas industry, brine is disposed into SWD wells via underground injection. The cost of disposal is dictated by the depth of the disposal interval, the formation characteristics (i.e., thickness, skin, permeability, pore pressure, frac gradient, porosity, injection area), tubular sizes and the maximum allowable wellhead injection pressure. The anticipated fluid volumes to be injected into each well, well life and the number of required injection wells are critical in assessing the true cost of managing an underground injection project. Unrealistic assessments initially can result in less than desired economic consequences.

This paper is a description of an underground injection cost model that will provide the capital and operating costs and optimize those costs based on hydraulic fracture design under specified reservoir conditions.

Generally, the process to develop brine disposal operating cost include the use of 3D reservoir, fracture and economic models. Various sensitivities must then be run and the results compiled in order to property estimate capital and operating costs. This model incorporates all key parameters and sensitivity analysis is done very quickly with a minimum of input. The model has correlations for many parameters that need to be estimated or calculated utilizing conventional models. This decreases the amount of design time, data required and familiarity with sophisticated models, and allows for easier parametric analysis. The model also allows for the user to input and modify additional parameters if the data is available.
Fundamental Study Makes Improved Air Drilling Technology Possible
Authors: Adewumi M. A. , Tian Shifeng , Watson R. W.
Published: December 2007

Because of poor understanding of the wellbore hydraulics involved in air drilling, the operating conditions are not optimal and consequently costs are higher in terms of rig time, personnel time, and equipment. Moreover, various post-drilling wellbore repair operations must often be performed to repair the damage done to the formation in the pay zone region in an improperly designed air drilling operation.

The importance of having a thorough understanding of wellbore hydraulics in air drilling can not be over-emphasized. Predictive capability of the hydraulics involved arises mainly from the intricate interactions between the wellbore, the drill string, the formation, and the particulate transport in the wellbore-drill string annulus. Lack of this understanding and the resulting lack of predictive capability leads to unexpected occurrences downhole, which at times lead to catastrophic fatality. An adequate understanding of the wellbore hydraulics will evolve into appropriate predictive capability, which can aid in the reduction of operational costs and risks involved and can help to provide optimal operation. The results of the work summarized in this paper will significantly enhance the scientific base for this highly desirable and economically attractive technology.
A Unique Experimental Study Reveals How to Prevent Gas Migration in a Cemented Annulus
Authors: Talabani Soran , Chukwu G. A. , Hatzignatiou D. G.
Published: December 2007

An experimental study was carried out to investigate the performance of new cement additives in controlling or eliminating gas migration through cemented wellbore annulus. The shrinkage behavior of the proposed cement slurries was obtained as a function of time and applied pressure at constant bottom hole temperature. Ultra-sonic measurements were correlated with the strength and bulk density of the cement. These measurements were used to screen out cement slurries for further testing in a cement simulation unit This unit consists of a 7″ casing pipe placed inside a 10″ controlled temperature water bath. The experimental unit was 6 ft long and was used to simulate borehole pressure and temperature conditions. The borehole was modeled by drilling a 2″ diameter hole through 2.5 ft long cylindrical core samples.

A large number of additives was tested to evaluate their effects on the cement volume fluctuations which are the primary causes of gas migration. A thorough procedure was followed to evaluate the effectiveness of all tested additives in controlling or eliminating the creation of micro-fractures during cement setting under borehole pressure and temperature conditions. The results obtained from this extensive experimental study show that the use of the proposed additives decrease significantly the cement volume fluctuations during cement setting.

The new cement additives proposed in this study reduce the contraction-expansion mechanism effects during cement slurry setting, thus minimizing and controlling the creation of micro-fracture.
Development of Asphaltene Phase Equilibria Predictive Model
Authors: Nor-Azlan N. , Adewumi M. A.
Published: December 2007

Asphaltene deposition is a very serious and complex problem. The damaging effects of this problem are common in all facets of petroleum production, processing and transportation. The mechanisms of asphaltene precipitation are still not fully understood due to the lack of understanding of the physicochemical behavior of asphaltene as it exists in the crude oil system. In this paper, a model based on the statistical thermodynamics of polymer solution is described for the phase behavior of asphaltenes. A Vapor-Liquid-Liquid Equilibria (VLLE) model is employed, using separate VLE and LLE calculations to predict the phase splits (vapor, asphaltene and crude oil fractions). The model uses the concept of material balance by coupling with the Flory-Huggin theory of polymer solution. Various theoretical equations of state are employed as options for the estimation of the component properties for the lighter fraction. The properties of the heavy fractions in the crude oil system are determined using empirical correlations. The resulting model allows us to predict the onset of asphaltene flocculation as a function of temperature, pressure and compositional changes in the crude oil system. This model can be used as a basis for designing petroleum production systems, including separator design, production well performance analysis, pipelines and EOR projects.
A Comparative Analysis of the Performance of Two-Phase Relative Permeability Models in Reservoir Engineering Calculations
Authors: Siddiqui Shameem , Ertekin Turgay , Hicks P. J.
Published: December 2007

A comparison of ten two-phase relative permeability models is conducted using experimental, semi-analytical and numerical approaches. Relative permeabilities from the models are compared with data obtained from 12 steady-state experimental runs on Berea and Brown sandstones using different combinations of three white mineral oils and 2% CaCl2 brine. Relative permeability data from four of the experimental runs are used to predict the displacement performance under Buckley-Leverett conditions and the results are compared against those predicted by the models. Finally, waterflooding performances predicted by the models are analyzed at three different viscosity ratios using a twodimensional, two-phase numerical reservoir simulator. The model results are compared against the experimental data using three different criteria. The models predict relative permeability to oil, relative permeability to water and relative permeability ratio values with varying degrees of success. The Wyllie-Gardner, Honarpour and Fatt-Dykstra models predict the best values for the relative permeability ratios. The Wyllie-Gardner, Honarpour and Burdine models give better results than the other models under Buckley-Leverett type displacement conditions. The simulator runs show that all models are able to run without problems (for the given conditions) although the Naar-Henderson model yields significantly different results than the other models. The simulator data show that as the oil-water viscosity ratio increases, the difference of performance predicted by different models diminishes. Overall, the Wyllie-Gardner and Honarpour models are found to yield consistently better results than the other models at the experimental conditions.
Drag - Bit Model Including Wear
Authors: Hareland G. , Rampersad P. R.
Published: December 2007

The model presented in this paper is a new approach to predicting the performance of full-hole and core drag bits. The model is based on theoretical considerations of single-cutter rock interaction, lithology coefficients and bit wear. Several new modeling features are introduced, these include "equivalent bit radius", "dynamic cutter action", "lithology coefficients" and "cutter wear". The model is applicable to all types of drag bits (Natural Diamond Bits (NDB), Polycrystalline Diamond Compact Bits (PDC) and any Geoset Bits) with correct cutter geometrical description. The model is useful for pre-planning, day to day and post drilling analysis, as well as drilling optimization.

Application of the model to evaluate drag-bit performance has shown good results in several lab and field cases. The advantages of this model include, optimization of operating parameters, optimization of bit parameters and support of a total drilling system for penetration rate, solids control and hydraulics optimization. In addition, use of the model is simple and straight forward, data requirements are standard and readily available. Lithology coefficients can be obtained from lab data or one set of drill-off and/or bit performance test in the field. Penetration rates can be predicted by the model for different lithologiεs using rock strengths obtained from offset drilling or log data. In other words, the model will predict penetration rate for any set of operating conditions, formation description and bit parameters.