bluuebunny/crossref_metadata_2025 huggingface dataset:
Dry Forward Combustion with Diverse Well Configurations
Authors: Akin Serhat , Bagci Suat , Kok Mustafa V.
Published: December 2007

In situ combustion is a thermal recovery technique where energy is generated by a combustion front that is propagated along the reservoir by air injection. Most of the previously conducted studies report thermal and fluid dynamics aspects of the process. Modeling in situ combustion process requires extensive knowledge of reservoir data as well as reaction kinetics data. Unfortunately, limited kinetic data are available on the rates and the nature of partial oxidation reactions and the high-temperature combustion reactions of crude oils and their saturate, aromatic, resin, and asphaltene (SARA) fractions. Moreover, the impact of such data on the modeling of the in situ combustion process has not been investigated thoroughly. Thus, we modeled in situ combustion experiments conducted on a 3D semi-scaled physical model that represents one fourth of a repeated five spot pattern. In all experiments a vertical injector is employed whereas, both vertical and horizontal producers have been installed to recover two different crude oils (heavy and medium). Several locations for the producers have been tried while keeping the length of the wells constant: vertical injector-vertical producer, vertical injector-horizontal side producer, and vertical injector-horizontal diagonal producer. In these experiments horizontal side producers performed better than the others. We first simulated the experiments by incorporating a kinetic model that is based on grouping the products of cracking into six pseudo components as heavy oil, medium oil, light oil, two non-condensable gases and coke using a commercial thermal simulator (CMG's STARS). Seven chemical reactions were considered: cracking of heavy oil to light oil and coke, heavy oil burning, light oil burning, and coke burning. Most of the experiments were history matched successfully with the exception of ones where a diagonal horizontal producer was used. We then repeated the simulations using SARA kinetic parameters. We observed that all matches were somewhat improved. We finally present a discussion of application of the models to field scale.
How New Horizontal Wells Affect the Performance of Existing Vertical Wells
Authors: Shirif Ezeddin E.
Published: December 2007

Horizontal wells are reviving many marginal oil fields through accelerated oil production. In some fields, a single horizontal well produces as much as all the vertical wells put together. While there are prolific results as far as the profitability of the operation is concerned, there are other pertinent questions that arise. Does the vertical well flow pattern suffer as a result of horizontal well production? Does the ultimate oil recovery increase as a result of horizontal well operation? Given a pattern of vertical wells, can a horizontal well location be so chosen that the total oil production (and recovery) is maximized? These are the questions this paper attempts to address.

The results show that horizontal wells do indeed capture the oil in the drainage area of vertical wells. The extent of this "loss" depends on several factors. These include direction and allocation of the horizontal well within the drainage area, position of the horizontal well between the vertical boundaries, permeability anisotropy, net pay thickness, and oil viscosity. For a given pattern, there is a horizontal well configuration that maximizes the total production rate. The question of ultimate oil recovery is quite complex, and it may be said that in light oil reservoirs a horizontal well would tend to increase the ultimate oil recovery. Although it is concluded that, each of these factors ascribes to significant effects, it is the location of horizontal well that warrant the greatest effect on overall performance of vertical well.
A Method of Integrating Capillary Pressure and Relative Permeability Data Into a Full Field Numerical Simulation of Main Body "B" Reservoir, Elk Hills Field, California
Authors: Hampton Thomas J. , Singh S. P.
Published: December 2007

There are several major reservoirs within Elk Hills Field with a large dataset of capillary pressure and relative permeability data. Several major reservoir studies are underway to assist in the further development of this world class field recently acquired by Oxy. A fullfield simulation has been tasked to quickly enhance the reservoir management of upper Main Body "B" Reservoir.

The challenge is to have a representative reservoir description that efficiently utilizes the wide range and large data set that is available. This is needed to fully model this complex, layered, turbidite reservoir (Stevens sandstone in Miocene Monterey formation). Also needed, is the ability to integrate additional laboratory data as it becomes available since modern core has recently been obtained. Main Body "B" has 42 sets of Capillary Pressure (Pc) from 7 wells, 29 sets of relative permeability to water from five wells, and 19 sets of relative permeability to gas from four wells. The laboratory capillary pressure was obtained in brine, gas, or mercury fluids. Most of the data was obtained in the 1970's.

By using an emerging innovative SCAL software program, some of the major tasks performed were the following: prepare a database of special core analysis, perform quality control, effectively convert the measured data to consistent units and field conditions, generate Leverette J-function, calculate height of saturation plane above free water level, group multi-phase rock fluid data according to hydraulic flow units, transform laboratory data into "rock" curves for input into ECLIPSE simulator and automatically assign curves to grid cells. This feature resulted in significant time savings to Oxy in developing an integrated model of Main Body "B" Reservoir at Elk Hills, where many different flow units were observed. Further, the quality of reservoir description is significantly improved by using this tool. Also, as additional data becomes available, it can quickly be incorporated into the model. By improving the quality of the reservoir model, accuracy in development planning is expected.
Control of Lost Circulation in Fractured Limestone Reservoirs
Authors: Davidson Eric , Richardson Lee , Zoller Simon
Published: December 2007

Fractured limestone formations present a great challenge to the Well Engineer in the designing of oil/gas wells. In the upper hole sections it may be acceptable to cure severe lost circulation by judicious use of cement or other non-reversible treatments, but in the case of a fractured reservoir the use of such treatments is not acceptable due to the damaging nature of the treatment. In really severe cases of lost circulation the only option may be to drill ahead, accepting losses, and having in place a floating mud cap. This procedure, however, is far from ideal due to the many uncertainties that prevail during such operations.

This paper deals with experiences gained while drilling wells in a highly fractured, vugular limestone reservoir offshore Italy. The reservoir in this case is dominated by very low matrix porosity rock but has highly fractured and karst related vugular porosity. These fractures and vugs are the main producing and stock tank oil originally in place (STOOIP) containing elements. Therefore the permanent plugging of the fracture/vugular porosity is not an acceptable option in the cure of lost circulation. Previous operations were unsatisfactory; when a conventional drilling fluid was used to drill the reservoir lost circulation resulted which rapidly gave way to total losses. Attempts to cure the losses were unsuccessful and the well was drilled ahead blind with seawater with no returns.

The problem was addressed by developing and implementing a loss control strategy for a subsequent well. The approach used an unconventional highly shear thinning fluid as the ‘drill-in’ fluid, the intention being to use the highly thixotropic nature of the fluid to control the rate of loss in the first instance. As losses became more severe, two component, cross-linking polymer pills were pumped to seal the loss zones and restore circulation.

This staged approach for controlling the losses was highly successful. Several incidences of total lost circulation were encountered and cured with the result that 258 m of reservoir section were drilled and successfully evaluated.

The techniques developed and the lessons learned during this operation will be of interest to engineers working in areas such as the Timor Sea, the Australian NW shelf and various regions of Indonesia, where similar lost circulation problems are common.
Aqueous Foams for Underbalanced Drilling: The Question of Solids
Authors: Herzhaft Benjamin , Toure Abdoulaye , Bruni Fabrice , Saintpere Stephane
Published: December 2007

Among the existing non-conventional drilling operations, underbalanced drilling offers several benefits such as prevention of lost circulation and formation damage, increase of rate of penetration and reduction of differential sticking occurrence. In underbalanced drilling, the pressure of the drilling fluid is intentionally maintained below the formation pore pressure. Specific fluids are used in order to achieve underbalanced conditions: gas, mist, aerated mud or foam. Drilling with foam is very valuable due to its very low density coupled to its excellent cuttings carrying ability, but characterization of foam properties under drilling conditions is still incomplete and this could be an obstacle to the use of this technique by operators. This work is a part of a research program on drilling foams characterization conducted in collaboration between IFP and Totalfinaelf and focuses on the properties of aqueous foams when in contact with solids. The first part of the study deals with the incorporation of solids such as clays into the foaming liquid formulation; experimental measurements show that addition of swelling clay leads to very good stability properties without the necessity to add polymeric additive. Furthermore, clay addition provides good filtration properties with the formation of a filter cake, and this is important in case of accidental overbalanced condition during drilling operation. Lubricity properties of foam formulations were also characterized. The second part of this work is a characterization of the solid transport properties of aqueous foams. An experimental setup based on the weighting machine principle was elaborated. It allows the measurement of solids removal under various drilling conditions (circulating time and inclination angle, cuttings size and concentration). A new method for describing solids removal is proposed. Dimensionless numbers involving all the fluid parameters permit to describe transport properties and to bring out critical conditions. Extrapolating these numbers to the well could provide an evaluation of the critical parameters necessary to clean inclined and horizontal wells.
Improved Estimation of Hydrocarbon Reserves Using High-Definition Lateral Log Array Data in Vertical and Highly Deviated Wells
Authors: Frenkel M. A. , Zhou Z.
Published: December 2007

The conventional dual laterolog (DLL) instrument, providing valuable information on formation resistivities, has been used in the petroleum industry for many years. However, in many situations, physical limitations of the DLL (e.g., limited vertical resolution, poor radial resolution in the presence of deep invasion, incorrect readings due to the Groningen effect, artifacts occurring in deviated wells) do not allow the interpreter to obtain the required information. Moreover, DLL data interpretation is normally accomplished on a level-by-level basis (1-D), which may result in overlooking hydrocarbon-bearing formations, underestimation of reserves, and low confidence in the interpretation results.

Currently, when oil production originates in thinly laminated reservoirs penetrated by vertical or highly deviated wells, the DLL tool alone cannot satisfy industry requirements for accurately predicting formation resistivity. The new High-Definition Lateral Log (HDLL) tool was developed to provide high-resolution array resistivity measurements and overcome most of these shortcomings.

The HDLL array tool performs a detailed radial sounding of the formation to evaluate the drilling fluid invasion profile. The tool provides a high vertical resolution detecting thin beds up to a 9-in. thickness. The data does not suffer from the Groningen effect and borehole dip artifacts. The resistivity image of the formation around the borehole, delivered at the well site, provides information necessary to delineate permeable zones and supports immediate operational decisions. Application of 2-D/3-D inversion-based interpretation allows the interpreter to recover the true formation resistivity and thus more accurately delineate and estimate the hydrocarbons.

The scope of the paper is to briefly introduce the HDLL technology and present quantitative results of petrophysical interpretations derived by the application of conventional and array-type resistivity measurements.

Two case studies for vertical and highly deviated wells from Oman and the North Sea demonstrate the added value provided by the HDLL technology. In the presented cases, HDLL-based interpretations show not only improved delineation of the known reservoirs but also extra pay intervals overlooked by DLL-based interpretations. The hydrocarbon saturation derived with the application of HDLL data is higher than the hydrocarbon saturation derived by the application of the conventional petrophysical interpretation. Use of the entire data suite of array data provides a much higher level of confidence in the presented hydrocarbon estimates.
Well Test Analysis in Gas-Condensate Reservoirs
Authors: Gringarten A. C. , Al-Lamki A. , Daungkaew S. , Mott R. , Whittle T. M.
Published: December 2007

Published analyses of well tests in gas-condensate reservoirs when pressure drops below the dew point are usually based on a two-zone radial composite model, representing regions of condensate drop-out around the wellbore and of initial gas composition away from the well. Laboratory experiments, on the other hand, suggest that three different mobility zones could exist: (1) an outer zone away from the well, with the initial liquid condensate saturation; (2) a zone nearer to the well, with increased condensate saturation and lower gas mobility; and (2) a zone in the immediate vicinity of the well with high capillary number which increases the gas relative permeability, resulting in a recovery of much of the gas mobility lost from condensate blockage. This paper investigates the existence of this latter zone in well test data. An example of well test analysis is discussed, which illustrates the difficulty of identifying such a zone as, in many cases, build-up and/or drawdown data are dominated by wellbore phase redistribution effects. Where the three zones can be identified, data are analyzed using a three-zone radial composite model to yield a complete characterization of the near-wellbore effects, and in particular the knowledge of the various components of the total skin effect: mechanical skin; rate-dependent two-phase skin; and skin due to gas condensate blockage. The existence of the three zones and the results of the analysis are verified with a compositional simulator where relative permeability depends on capillary number.
History Matching Geostatistical Reservoir Models with Gradual Deformation Method
Authors: Le Gallo Y. , Le Ravalec-Dupin M.
Published: December 2007

This paper presents a new history matching methodology to constraint 3-D geostatistical reservoir model to well and production data. This methodology is a general inversion procedure based upon the gradual deformation method. It allows for constraining simultaneously petrophysical, geostatistical and reservoir parameters to dynamic production data.

The gradual deformation algorithm creates realizations, which evolve smoothly while preserving the global statistical features of the model. The deformation process is coupled with an optimization algorithm to automatically match production history. After validating the inversion process on synthetic data, we focused on real data. The inversion process involves up to fourteen parameters constrained through a fifteen-year production history. A coarse geostatistical model conditioned to rock-types and porosities observed at well locations describes the geological uncertainties. The petrophysical uncertainties are summarized within the permeability-porosity laws considered for the two dominant rock-types in the reservoir. The main reservoir uncertainties are the strengths of the edge aquifers and the critical gas saturations for each rocktype. The final match is obtained after several inversions and is quite satisfactory with respect to well pressure, oil and water flow rates.
Conditioning reservoir models to dynamic data - A forward modeling perspective
Authors: Srinivasan Sanjay , Caers Jef
Published: December 2007

In order to predict accurately future production performance, a reservoir model should reflect the actual patterns of permeability connectivity (flow paths and barriers). Information about such patterns of connectivity is carried by flow response data recorded at wells. However, the flow response data are influenced by many factors other than permeability connectivity such as boundary conditions and fluid property variations. This paper presents a neural network-based procedure for filtering the information related to the permeability field in flow response data. The flow response data is modeled as specific multiple point averages of permeability values in the neighborhood of the well. Such multiple point averages allow accounting for the spatial connectivity of the permeability field. The superiority of such multiple point averages over single point permeability averages for representing flow response data is demonstrated over several reservoir examples.

The ultimate quest is to integrate the permeability connectivity information contained in the flow response data into the numerical reservoir models. This amounts to ascertain that the permeability numerical models identify the previous multiple point averages. A Markov chain Monte Carlo simulation algorithm is implemented to perform this identification. Alternative equiprobable permeability fields are generated which, in addition to reproducing the production data, conform to a prior model for the spatial variability of the permeability field. The results demonstrate that flow simulation on the simulated permeability fields do indeed match historic well test data accurately. More importantly, future reservoir performance predictions are rendered more accurate.
Geostatistical Reservoir Characterization Using Interwell Seismic Data
Authors: Justice J. H. , Woerpel J. C. , Watts G. P. , Waddell W.
Published: December 2007

Geostatistical techniques are currently finding widespread use in reservoir characterization. Most hard data which is available for use in geostatistical procedures is obtained at generally widely spaced production or injection wells. This fact makes estimation of spatial statistics for the reservoir rock difficult since the interwell volume is not directly accessible for measurement.

Interwell borehole seismic imaging technology is now reaching the point where high-resolution maps of seismic shear and compressional wave velocity fields can be constructed in the interwell volume between wells. Biot-Gassmann theory allows us to relate shear and compressional seismic velocities to porosity when additional rock properties are known or can be inferred.

Using data acquired in a shallow-shelf carbonate reservoir in the Permian Basin, as part of a DOE Class II Oil Project, we have used interwell seismic data to infer porosity distribution between wells. Using cross-plots, permeability distributions were also obtained. These were then used to directly estimate azimuthal spatial statistics for porosity and permeability in the reservoir. Geostatistical procedures were then used to build highly detailed 3-D reservoir models, using these spatial statistics. After a period of CO2 injection in the reservoir, similar techniques were used with monitor surveys to generate 3-D volume images of injected CO2 in the project.
A Direct Method for the Identification of the Permeability Field of an Anisotropic Porous Medium
Authors: Zhan Lang , Yortsos Yanis C.
Published: December 2007

In a recent publication1 we proposed a direct method for the inversion of the permeability field of an isotropic porous medium based on the analysis of the displacement of a passive tracer. By monitoring the displacement front at successive time intervals (for example, using a tomographic method), the permeability can be directly obtained from the solution of a non-linear boundary-value problem. In this paper we extend this approach to the case when the porous medium is anisotropic.

When the principal axes of anisotropy are known and fixed, a procedure is proposed, in which the tracer is injected two (or three) consecutive times along the two (or three) principal directions (for the case of a 2-D (or 3-D) problem, respectively). It is shown that the diagonal components can be obtained from the solution of two (or three) coupled boundary-value problems involving the experimentally obtained fields of arrival times. Numerical examples show that the method works well when the permeability variation is not very sharp (for example, for correlated distributions). When the permeability tensor is full and the principal axes vary in space, we propose a procedure involving the injection in three different directions (for the case of a 2-D problem). In principle, the components of the permeability tensor can be determined from the solution of three coupled boundary-value problems. However, the inversion method encounters significant numerical problems. For the case of small off-diagonal components, a practical procedure is proposed to decouple the problems in the inversion method for both 2-D and 3-D.
On the Quest for Ester-Base Mud System Impact on Data Acquisition
Authors: Lugol R. L. , Dodman C. A. , Crowe J. , Louis A.
Published: December 2007

Oil-Base Mud (OBM) systems have been used in the oil and gas industry for many years. Historically OBM systems have contained aromatic compounds. Environmental concerns linked to the use of OBM pushed the industry to develop Synthetic-Base Mud (SBM) systems with no aromatic content. This paper focuses on the use of ester-base mud (EBM). EBM was originally used in the top-hole sections of wells. It is now extensively used to drill the complete range of exploration, development, water source and water injection wells.

This paper will demonstrate that EBM has a significant impact on well measurements (FEWD and wireline logging, mud logging, coring, etc.) when compared to Water-Base Mud (WBM) or traditional OBM. Examples derived from offshore and onshore fields in Nigeria will be presented. Local efforts to investigate the effect of EBM, have been carried out in Nigeria by Oil and Service companies. These results seem to indicate that this effect causes a modification of the mud filtrate invasion profile within the formation and results in a complex interaction with the fluid in place. Adverse effects have been observed which have consequences on formation evaluation data and the subsequent static and dynamic reservoir evaluation. A major concern is that Original Oil In Place (OOIP) calculations are systematically reduced. Therefore, on critical wells where formation evaluation is a key issue, the choice of such mud systems needs to be balanced with the potential loss of geological and petrophysical information and the anticipated reduction in drilling cost.

A comprehensive study, coordinated by a special interest group, needs to be initiated on a larger scale by the companies concerned. The objective of the study would be to understand the physics and chemistry of SBM on rocks and formation and develop corrections for log and core measurements. This study would benefit the worldwide users of SBM drilling fluids. This paper will discuss the observations and propose a program to better understand the phenomenon and improve formation evaluation accuracy.
Integration of Dynamic Data of Pilot Waterflood with Rock Fabric -Implications for the Full Field Waterflood Startup in Mauddud Reservoir, North Kuwait
Authors: Al-Ajmi Hussian Zayed , Mukherjee Raja , Chetri Hom Bahadur
Published: December 2007

The Mauddud limestone of Early Cretaceous is multi-billion barrel depletion drive reservoir undergoing re-development with a planned 260,000 BWPD seawater injection. Injection-production history and dynamic data integration with a static reservoir description of the two waterflood pilots illustrates much of what can be expected in the larger scale waterflood. Detail cross-sections were build incorporating geological, petrophysical, surveillance and production data to understand reservoir performance under water flood.. Geocellular models based on 3-D seismic and detail core sedementology was constructed and simulation was done to facilitate this understanding. Over the two and half years of Pilot life great variety of data were acquired which includes: extensive open hole logs including CMR/NMR, FMI and RFT, Conventional and preserved cores, core sedimentological and fracture study, Geochemical (Iatroscan & Residual Salt Analysis) analysis, Geomechanical & Reservoir stress analysis, interference testing, production and injection profile logs, time lapse pulse neutron logs, static bottom hole pressures and pressure build up surveys. Synergistic integration and interpretation of multidisciplinary pilot wells data, has given a detail insight of the controls of fluid flow in the reservoir and the understanding was carried forward to the full field development of Mauddud reservoir using I-9 spot pattern flooding.

The major controls on the pilot water movements are; 1) Facies variation and thief zones, 2) Injector conformance 3)regional reservoir pressure gradients around the pilots.

The pilots have proven the pressure connectivity on the larger scale (250 acre inverted 9 spot) through surveillance gathered outside the pilot patterns. This adds confidence to the predictions of flood performance success across the development area and confirms that the planned pattern flood is appropriate. Mechanism of water breakthrough was studied and potential sweep efficiencies in the relatively lower permeability facies were analyzed through production and pulsed-neutron logging and by in-fill drilling. The three vertical hydraulic units identified by field RFT data were confirmed by vertical sweep profile. The more depleted upper zone is the target of the existing pilots. These characteristics are expected in the larger scale waterflood and perforation strategy is designed to optimize conformance between injector and producer and to minimize early injection breakthroughs and maximize vertical and areal sweep efficiency. The observed time to water breakthrough, observed vertical and aerial sweep, and the controlling geologic description has been used to refine reservoir simulators allowing them to more accurately predict production and more importantly water-cut profiles and recovery factors for this important redevelopment.
Understanding Coning Performance in a High-Anisotropy Reservoir: The Burgan Reservoir Case Study
Authors: Kabir C. S. , Ma E. D. C. , Dashti Q. , Al-Shammari O.
Published: December 2007

Water cones largely dictate oil recovery in a typical bottom-water situation. Major parameters influencing coning include mobility ratio, producing rate, completion interval, and anisotropy. We conducted a systematic study to understand the influence of these and other parameters on coning. Our aim was to develop producing and completion rules for managing the Greater Burgan’s Third Middle Sand (3MS) reservoir in Kuwait.

The building blocks of our study were: (1) detailed geologic modeling using core and openhole log data, (2) geostatistical modeling for 3D sector modeling, (3) transient-pressure testing, (4) production logs, and (5) cased-hole saturation logs. Singlewell, 2D radial models were built to understand various elements of coning for existing completions. We also explored alternative completions to mitigate coning. The study included the use of single- and dual-lateral wells and cone-reversal techniques. Follow up studies using a 3D-sector model confirmed some of the findings of single-well modeling.

Results show that high anisotropy provides near piston-like displacement and, consequently, completing at the top of the bed appears prudent in a vertical well. High producing rate tends to leave higher remaining oil saturation than those do at moderate rates. A combination of high-anisotropy and low- length-to-thickness ratio makes horizontal completions unattractive in the crestal area of the field.
Effects of Phase Behavior, Dispersion and Gridding on Sweep Patterns for Nearly Miscible Gas Displacement
Authors: Haajizadeh M. , Fayers F. J. , Cockin A. P.
Published: December 2007

In a previous paper, Haajizadeh et al [1] used compositional simulation to investigate the effects of physical dispersion, and short scale heterogeneities with consequent viscous fingering, on rectilinear displacement by nearly miscible gas. It was shown for near-miscible processes that the dispersive/fingering effects of heterogeneities in 2D-rectilinear flows could be matched quite well through use of an appropriately chosen grid size in an equivalent 1D-compositional model.

In the present paper, we extend this work by investigating 2D-areal sweep patterns for two different well configurations, using the same types of phase behavior. It is well known that areal sweep for first contact miscible (FCM) processes is unstable and difficult to compute with finite difference solutions; however, dispersion effects reduce the effective viscosity ratio for multi contact miscible (MCM) processes because of the departure from proper miscibility. Additionally, the presence of heterogeneities with short correlation lengths creates noise effects which also have an independent stabilizing influence. This can augment the benefits of loss of miscibility.

We show that there can be a "best" grid size in 2D-areal configurations to allow partial cancellation of errors associated with omission of short range heterogeneities. The optimum choice of gridding is found to depend on well positions in terms of diagonal or parallel gridding, and the type of phase behavior. In the absence of heterogeneities, fine grid near-miscible solutions with single point upstream weighting display strong grid orientation errors, which are improved by using a 9-point scheme. In the presence of heterogeneities, the grid orientation problem is much reduced and a suitably chosen coarse grid for a homogeneous problem can give an areal sweep shape similar to that from the 9-point fine grid with heterogeneities. We demonstrate that improvement in areal sweep resulting from the presence of heterogeneities can more than offset the loss of local displacement efficiency associated with degraded phase behavior.

We also report on some results for the dispersive nature of short range heterogeneities on vertical sweep pattern for a condensing/vaporizing drive in a vertical cross section, where there is a consequent broadening of the gravity override tongue. This can also improve recovery performance. We show that an appropriate size of gridding in a homogeneous model can again give some compensation for omitted sub-grid heterogeneities. The gravity override behavior is more sensitive to choice of the Δz- than Δx-interval, so there are prospects for choosing "effective" grid sizes to deal with sub-grid heterogeneities in both areal and vertical sweep aspects of a 3D-problem. However, selection of appropriate gridding for vertical sweep will also depend on other factors such as gravity numbers, asymmetry in correlation lengths, use of WAG etc.
A Low-Cost PET System for Use in Flow Experiments of Porous Media
Authors: Haugan Are
Published: December 2007

A low-cost two-dimensional PET system which can visualize tracer flow inside porous media has been constructed. It has thoroughly been tested, and successfully been used to image fingering inside porous media by using 22Na+ as passive water tracer. The system consists of two collimated NaI(Tl) detectors. During a scan the porous media is moved along a line perpendicular to the line between the two detectors with the help of a linear position table, and rotated around an axis perpendicular to the plane set by these two lines. The simplicity of the PET system almost completely eliminates the problems with Compton scattering, random coincidences, radial elongation and individual LOR efficiency. Thus, some of the problems with commercial PET systems are strongly reduced in our PET system. The developed PET system is modular, and consists primarily of components that are common in laboratories performing nuclear measurements. This made it a low-cost system, and may increase the availability of this imaging technique. It is concluded that PET has the ability to become a powerful tool in such studies.
Refracture Reorientation Enhances Gas Production in Barnett Shale Tight Gas Wells
Authors: Siebrits E. , Elbel J. L. , Hoover R. S. , Diyashev I. R. , Griffin L. G. , Demetrius S. L. , Wright C. A. , Davidson B. M. , Steinsberger N. P. , Hill D. G.
Published: December 2007

Refracturing can be used to increase production in poorly fractured wells. A different application of this technology is to refracture wells with strong initial fractures. In this paper, we provide evidence of increased production due to refracturing two tight gas wells having deeply penetrating initial fractures. Surface tiltmeter measurements show refracture orientations at oblique angles to the azimuth of the initial fractures.
Hydraulic Fracture Growth through Offset Pressure-Monitoring Wells and Boreholes
Authors: Jeffrey R. G. , Settari A.
Published: December 2007

The growth of hydraulic fractures through nearby wells and boreholes in which pressure was monitored has been recorded as part of eleven field experiments conducted over the past few years. These direct measurements of fracture growth are compared to one another and to predictions of growth made using numerical models.

The effect of fracturing into an open well, which then acts as a high fluid loss sink, is illustrated by some of the data and through numerical modeling.
Evolution of the Production Semisubmersible
Authors: Lim E. F. H. , Ronalds B. F.
Published: December 2007

Semisubmersibles and FPSOs are the two most common floating production solutions and they compete in many field developments. The first production semisubmersible in 1975 preceded the prototype FPSO by two years. Both concepts were more or less on a par for the next two decades, until the dramatic surge in popularity of the FPSO in the late 1990s. However, the continued adoption of semisubmersibles indicates that they retain advantages over FPSOs in certain situations.

Semisubmersibles have seen application in most petroleum provinces around the world outside Australasia. Traditionally semisubmersibles were converted drilling rigs used for EPS and short field life developments. Many are located in only moderate water depths. However, recent semisubmersibles have been adopted for large production facilities. They have also been used in ultra-deepwater, and several semisubmersibles have held deepwater production records. Many of these developments are off Brazil and Norway. These changes in focus have required new-build semisubmersibles with novel hull forms in comparison with traditional drilling units.

The early popularity of semisubmersibles over FPSOs is related to their advantages in harsh environments. With the development and advancement of internal turrets, FPSOs have recently seen acceptance in severe North Sea conditions. Today, a principal driver for selection between semi-submersibles and FPSOs is the relative importance of workover capability and infield storage. Other key factors include the opportunity for gas export, the number of risers required and the availability of vessels for conversion.

The paper traces the evolution of the production semisubmersible and gives a comprehensive database of applications to date. A comparison of the relative merits of semisubmersibles and FPSOs for different production scenarios is also included.
A Simple Model To Predict Natural Gas Separation Efficiency in Pumped Wells
Authors: Harun A. F. , Prado M. G. , Serrano J. C. , Doty D. R.
Published: December 2007

A new mechanistic model to predict the natural separation efficiency in vertical pumped wells has been developed. The model is based on the combined phase momentum equations and a general slip closure relationship. New drag coefficient correlations have been developed corresponding to the bubbly (i.e. undistorted particle) and churn-turbulent flow regimes. The model indicates that the natural separation efficiency depends strongly on geometry, void fraction and in-situ gas flow rate.
Shale Stabilisation by Pressure Propagation Prevention
Authors: Carminati S. , Del Gaudio L. , Brignoli M.
Published: December 2007

Different commercial shale additives for wellbore stabilisation have been tested to clarify their mechanism of action and rank their performance. Specifically they have been evaluated for their capacity to prevent pressure propagation from the drilling fluid to the formation, and their impact on shale hardness. Pressure propagation experiments have been performed under high pressure-high temperature conditions. For the silicate muds, an ability to reduce pressure propagation was verified; for others, including cloud point glycols which have been suggested to plug shale pores, no strong effect was found. Shale hardness by indentation tests has been evaluated at ambient conditions after ageing at 80°C. Hardness tests give a clear indication that both cationic polymers and silicates increase shale strength, while glycols are effective in increasing shale strength and reducing pressure propagation only when the potassium ion is also present.

A new pore plugging system based on an oil-in-water emulsion has been demonstrated to prevent pressure propagation in laboratory experiments. Its effectiveness depends on the capillary entry pressure of the oil droplets into the shale pores.

Finally a few considerations on how to apply the research results in drilling operations are given.
Significance of the Non-Darcy Behavior on the Fluid Loss into High Permeability Formations
Authors: Civan Faruk
Published: December 2007

The constant property (incompressible) and variable property (compressible) filter cake models considering nonDarcian linear and radial flow conditions are facilitated for estimation of the filter cake thickness and the fluid loss into high permeability formations. These models can be applied for analyses of the filtration problems associated with the drilling, hydraulic fracturing, and workover operations.

The parametric studies demonstrate that nonDarcian flow conditions are more dominant during the build-up of incompressible filter cakes over high permeability formations without involving fine particles invasion and retention. The non-Darcian effects rapidly diminish for compressible cakes undergoing fines deposition within the cake matrix.
Surrogate Modeling-Based Optimization for the Integration of Static and Dynamic Data Into a Reservoir Description
Authors: Queipo Nestor V. , Pintos Salvador , Rincön Nestor , Contreras Nemrod , Colmenares Juan
Published: December 2007

This paper presents a solution methodology for the problem of estimating the distributions of permeability and porosity in heterogeneous and multiphase petroleum reservoirs by matching the static and dynamic data available.

The solution methodology includes, the construction of a "fast surrogate" of an objective function whose evaluation involves the execution of a time-consuming mathematical model (i.e. reservoir numerical simulator) based on neural networks, DACE modeling, and adaptive sampling. Using adaptive sampling, promising areas are searched considering the information provided by the surrogate model and the expected value of the errors.

The proposed methodology provides a global optimization method, hence avoiding the potential problem of convergence to a local minimum in the objective function exhibited by the commonly Gauss-Newton methods. Furthermore, it exhibits an affordable computational cost, is amenable to parallel processing, and is expected to outperform other general purpose global optimization methods such as, simulated annealing, and genetic algorithms.

The methodology is evaluated using two case studies of increasing complexity (from 6 to 23 independent parameters). From the results, it is concluded that the methodology can be used effectively and efficiently for reservoir characterization purposes. In addition, the optimization approach holds promise to be useful in the optimization of objective functions involving the execution of computationally expensive reservoir numerical simulators, such as those found, not only in reservoir characterization, but also in other areas of petroleum engineering (e.g. EOR optimization).
Aquifer Controls on Coalbed Methane Development in the Powder River Basin, Wyoming
Authors: Onsager P. R. , Cox D. O.
Published: December 2007

Development of coalbed methane (CBM) in the Wyodak-Anderson seams of the Powder River Basin, Wyoming, is one of the most active plays in the world. Compared to other CBM producing basins, the Powder River Basin subbituminous coal has relatively low gas content (20–50 scf/ton), but high permeability (100s of millidarcy to 1+ darcy). Because of the shallow depth, Powder River Basin CBM development is normally on 40- or 80-acre well spacing. Another significant difference between the Powder River Basin and other producing CBM basins is the fact that the coal seams of the Powder River Basin are overlain and underlain by large, thick aquifers that are essentially infinite-acting in nature. The degree of hydraulic connection between these aquifers and the coal is a critical factor in the economics of gas production from this play. Where the aquifers are well connected to the coal, water influx or leakance is high, leading to a nearly steady-state pressure environment that will deter efforts to dewater the coal and produce methane. Using reservoir simulation analyses and actual field data on gas and water production, this paper examines the effect of aquifer leakance on the producibility of the coal. Optimum well spacing in the Powder River Basin is shown to depend on having sufficient wells per section to lift the water that leaks into the coal from the aquifers. In fact, in some parts of the basin, aquifer leakance will maintain reservoir pressure high enough that it will curtail methane desorption and restrict ultimate gas recovery. Further testing and analysis to better characterize the aquifers and their connection to the coal is necessary.
The Lewis Shale, San Juan Basin: What We Know Now
Authors: Dube H. G. , Christiansen G. E. , Frantz J. H. , Fairchild N. R. , Olszewski A. J. , Sawyer W. K. , Williamson J. R.
Published: December 2007

In 1998, Burlington Resources (BR) initiated a study to characterize the Lewis Shale (Lewis) gas potential in the San Juan Basin (SJB) and optimize exploitation. Historically, most SJB production has been from naturally fractured, low permeability, Cretaceous sandstones (Dakota, Mesaverde, and Pictured Cliffs) or from the prolific Fruitland Coal. In the past, the Lewis, which lies between the Mesaverde and Pictured Cliffs Formations, was completed in only the few wells where large Lewis flow rates were encountered while air-drilling for deeper targets. However, the Lewis lies behind pipe in thousands of existing wells across the SJB. In a large number of these wells and in new Mesaverde/Dakota wells, the Lewis can be completed. The BR program includes performing geological, petrophysical, reservoir, stimulation, and production data analysis. From this data, reservoir characterization, completion optimization, and forecasting models were developed that indicate commercial Lewis potential through much of the SJB in both new and existing wells. Furthermore, the Lewis is more accurately characterized as a sandy siltstone, rather than a true shale such as the Devonian or Antrim Shale.
Benchmarking of Restimulation Candidate Selection Techniques in Layered, Tight Gas Sand Formations Using Reservoir Simulation
Authors: Reeves S. R. , Bastian P. A. , Spivey J. P. , Flumerfelt R. W. , Mohaghegh S. , Koperna G. J.
Published: December 2007

Studies by the Gas Research Institute have revealed that improved methods are needed to cost-effectively identify high-potential restimulation candidate wells. Subsequent research has had the objective of developing such methodologies, and testing them in the field. The techniques being investigated include production statistics, virtual intelligence, and type-curves. For various reasons, field activities have been slow to implement, limiting the feedback needed to fully test each candidate selection method. Therefore a reservoir simulation study was performed to test the methods. The simulation field model consisted of four reservoir layers of variable properties. Wells were drilled in three rounds over a 12-year period (120 total wells). Completion intervals were varied for each well, as were skin factors for individual layers. Before providing the data to the project team for analysis, noise was added. These model features and noise were incorporated into the exercise to best replicate actual field conditions. Restimulation potential was established by "restimulating" each well in the model and observing the incremental production response. Application of the various candidate selection techniques, and comparing the results to the known answer, has yielded several important conclusions. First, simple production data comparisons are not effective at identifying high-potential restimulation candidates; better producing wells tend to be better restimulation candidates. Virtual intelligence techniques were the most successful, correctly identifying over 80% of the theoretical maximum available potential. The type-curve technique was not as effective as virtual intelligence, but still achieved a 75% candidate selection efficiency.