bluuebunny/crossref_metadata_2025 huggingface dataset:
Reconstruction of 3D Network Model Through CT Scanning
Authors: Hou J. , Zhang S. K. , Sun R. Y. , Li Z. Q. , Li Y. B.
Published: December 2007

Digitized description of rock is one trend of flow modeling. The paper presents a method for reconstructing 3D network model of microscopic pore structure according to CT images of rock. Sequential CT images which can fully describe 2D microscopic pore structure of rock are obtained by using ACTIS-225FFi CT/DR/RTR microfocus CT equipment. 3D skeleton and pore-bodies of the porous media can be obtained through processing these images by using the thinning algorithm. On the base of analyzing the differences between the core model and the network model, pores and throats are extracted considering the geometrical equivalence through equivalent method of flow conductivity and shape factor. Thus, the conversion from CT scanned images of real rock into a 3D network model is realized, which can be used as a powerful tool in flow simulation. One advantage of the method lies in the fact that simplified geometrical objects, such as pores and throats, can be used to replace the irregular geometry with less calculating time while retaining the geometrical features and flow characters. Based on the method above mentioned, the paper takes well 70-1 of Kendong oilfield, China as an example to carry out the CT scanning experiment and to reconstruct the network model. It is found that there is a good agreement between the calculated parameters of network model and those of porosity, absolute permeability, capillary pressure curves as well as relative permeability curve measured in laboratory, which indicates that the network model can fully describe the microscopic pore and throat sizes as well as topology of rock.
A Three-Phase Quantitative Monitoring Method for CO2 Floods
Authors: Svor T. Richard , Globe Michael P.
Published: December 2007

Pulsed neutron logs have been used effectively for monitoring reservoir changes and, in many cases, predicting current water saturation. Monitoring becomes much more complicated when three phases (water, oil, and CO2) are considered simultaneously for analysis. Complex lithology and the resultant differences in the neutron capture cross section (sigma) of the rock matrix further complicate the determination of water and CO2 saturation.

The proposed technique uses open hole digital log analysis and a base run pulsed neutron log (PNC) to compute triangles whose vertices represent sigma and ratio (net near to far detector count rate) of 100% oil, water, and CO2 saturations for the given porosities. The triangles are computed and stored on a foot-by-foot basis. Subsequent PNC runs are analyzed by locating the latest sigma/ratio data point within its previously determined triangle and solving graphically for oil, water and CO2 saturations. This technique eliminates, for practical purposes, uncertainties caused by complex lithology.

The results from applying this technique in the Little Knife Field CO2 Minitest in North Dakota have demonstrated its utility. These results and an in-depth explanation of the technique are presented.
Three-Phase Relative Permeability Measurements Using the Centrifuge Method
Authors: Van Spronsen Engel
Published: December 2007

The centrifuge method for two-phase relative permeability measurements has been extended for use with three mobile phases. The oil and water production obtained from a sample rotated in an air-filled sample holder straightforwardly yields the three-phase oil and water (drainage) relative permeabilities along a trajectory in the saturation ternary diagram.

The criteria for reliable measurements are discussed. It is shown that these experimental requirements are similar to those for the two-phase case.

The extended centrifuge technique has been used for measuring the three-phase oil and water relative permeabilities on Weeks Island and Berea samples. The results of these experiments show that the shape of the oil isoperms in the saturation ternary diagram is concave when viewed from the oil apex. This shape implies a more favourable recovery for immiscible gas (CO2) injection into the Weeks Island B Sand than predicted on the basis of the convex oil isoperms calculated with the models of Stone or Hirasaki.
Lumped-Component Characterization of Crude Oils for Compositional Simulation
Authors: Hong K. C.
Published: December 2007

Compositional simulators using an equation of state to describe the phase behavior of multicomponent fluid mixtures are expensive to use because of the large number of iterative phase equilibrium calculations and large computer storage space required. It is thus desirable to keep the number of components used in describing a fluid mixture to a minimum. This paper describes a method for reducing the number of components without a significant loss of accuracy in describing the phase behavior. Peng-Robinson equation-of-state models with up to five pseudocomponents were developed for three reservoir fluids ranging from a bubble-point to a dewpoint fluid under initial reservoir conditions. These models are shown to match the laboratory-measured phase behavoir data almost as accurately as the more complex 14 to 17 component models originally used in reservoir simulation.
CO2 Injection for Tertiary Oil Recovery, Granny's Creek Field, Clay County, West Virginia
Authors: Watts Royal J. , Conner William D. , Wasson James A. , Yost Albert B.
Published: December 2007

Columbia Gas Transmission Corporation, with financial assistance from the U.S. DOE, planned and operated an Enhanced Oil Recovery Project in the Granny's Creek oil field, Clay County, West Virginia. The objective of the field test was to determine the feasibility and economics of recovering additional oil from a (flooded-out) low-oil saturated reservoir using carbon dioxide (CO2) for miscible displacement of residual oil.

The site selected for the test was a 6.7-acre (27,000 m2) portion of a former waterflood pilot test area. The waterflood pilot was highly successful for the area, producing over 4,000 barrels per acre (0.157 m3/m2) over the flood life. The reservoir tested was the Mississippian aged, Pocono Big Injun formation occurring at a depth of 2,000 feet (610 m). Residual oil saturation was approximately 30-35 percent. Porosity averaged 16 percent with an average reservoir permeability of 7 millidarcys.

CO2 injection was initiated in early June 1976. Injection was into four corner wells of a normal five-spot. A center production well and three observation/production wells were also located within the pattern. In the initial test, 10,000 tons (9,070 t) of CO2 was injected into the four wells, employing the WAG injection technique for mobility control. Due to pilot pressure distribution, less than 12 percent of the CO2 entered the pattern. In a second pilot operation phase, a single injection well minitest was initiated within the original CO2 pilot pattern. Over 2,100 tons (1,900 t) of CO2 was injected for this test. Oil production within the pattern during the first phase was over 4,000 barrels (640 m3) with a CO2/oil ratio of 2,500-5,000 scf/bbl (445-890 m3/m3). The minitest produced oil at a 17,337 scf/bbls (3,100 m3/m3) CO2 utilization rate.

Evaluation of the pilot has been most difficult due to complex reservoir heterogeneity and field operation problems. Presently, it does not appear that the CO2 miscible displacement process will be economical for tertiary oil recovery in such low-oil saturation reservoirs without better mobility control for greater sweep efficiency. The test results have determined though, that the CO2 process can mobilize and recover a significant volume of additional oil after waterflooding.
Enhanced Oil Recovery From Offshore Gulf of Mexico Reservoirs
Authors: Brashear J. P. , Morra F. , Haas M. R. , Payne S.
Published: December 2007

More than eight billion barrels of oil will remain in Gulf of Mexico reservoirs at the end of primary and secondary operations. This study is designed to determine whether a portion of this can be produced by enhanced oil recovery (EOR) methods. All oil reservoirs with more than 2.5 MMB original oil-in-place in the Federal Offshore region of the Gulf of Mexico were screened by geological criteria to determine general amenability to EOR. One hundred seventy-six individual reservoirs, in 100 "horizons" (near adjacency at comparable depth), were identified. In all, 40 fields had one or more geologically acceptable horizons. This paper describes the characteristics of these reservoirs and projects the timing of their abandonment. The prospective reservoirs are currently undergoing detailed technical and economic evaluation. The paper also includes this evaluation for example reservoirs. (Full results will be presented at the Symposium.)
A Method of Measuring Steam Quality and Heat Loss in Distribution and Downhole Piping
Authors: Pradt Louis A.
Published: December 2007

This paper describes a technique that can be used to determine the steam quality in the outlet of a once-through steam generator. The technique can also be used to measure the heat loss between any two points in a distribution and downhole piping system. The technique is based on the fact that a mixture of a vapor and a non-condensible gas condenses along a dew point curve, instead of at constant temperature as in the case of a pure vapor.
Field-Scale Wettability Modification—The Limitations of Diffusive Surfactant Transport
Authors: Stoll W. M. , Hofman J. P. , Ligthelm D. J. , Faber M. J. , van den Hoek P. J.
Published: December 2007

Densely fractured oil-wet carbonate fields pose a true challenge for oil recovery, which traditional primary and secondary processes fail to meet. The difficulty arises from the combination of two unfavourable characteristics: the dense fracturing frustrates an efficient water-flood; the negative capillary pressure retains the oil inside the matrix blocks because oil is the wetting phase. In the past decade, EOR researchers have studied options to chemically revert the wettability of carbonate rock while not decreasing the oil-water interfacial tension drastically, using a new class of surfactants. These chemicals termed "wettability modifiers" (WM) effectively reverse the sign of the capillary pressure function such that the capillary pressure becomes the driving force for oil expulsion from the matrix into the fracture system.

Previous publications on chemical wettability modification focused on the different chemical properties of the rock/oil/WM-brine system and demonstrated up to almost full oil recovery from core plugs. Little attention, however, has been paid to the mechanism underlying the transport of the chemical into the matrix block and to proper scaling of laboratory results to reservoir size. The present study aims to demonstrate that imbibition after wettability modification is diffusion-limited. To this end the recovery profiles for spontaneous capillary imbibition as well as for imbibition after wettability modification are calculated. The results are then used to match the data of Amott cell imbibition experiments. It is confirmed that in either case the cumulative recovery is initially proportional to the square root of time. Imbibition after wettability modification, however, takes about 1000 times longer than spontaneous capillary imbibition into a water-wet medium. The slow recovery observed for the case of imbibition after wettability modification is in excellent agreement with the assumption that, in the absence of significant spontaneous imbibition, the wettability modifier must first diffuse into the porous medium to unfold its action. In any diffusion process the time scale is linked to the square of the length scale of the medium. Therefore, it would take up to 1000 times longer, equivalent to 200 years, before the same recovery is obtained from a metre-scale matrix block as is obtained from a centimetre scale plug in the laboratory in 100 days.

Consequently, unless a significantly faster transport mechanism for the wettability modifier is identified, or unless viscous forces or buoyancy enable forced imbibition, chemical wettability modification of fractured oil-wet carbonate rock does not provide an economically interesting opportunity.
Connectivity of Spatially Correlated Fractures: Simulation and Field Studies
Authors: Masihi Mohsen , King Peter
Published: December 2007

The nature of fluid flow in fractured reservoirs of very low matrix permeability depends on the geometrical properties of fractures as well as the connectivity of the fracture network. Percolation theory is the obvious tool to rapidly estimate the connectivity and its associated uncertainty through some algebraic scaling laws. However, the usual scaling laws do not consider anisotropy, fracture size distribution and fractures’ interactions. We have recently addressed the effects of anisotropy in orientation of fractures (SPE 94186) and fracture length distribution (SPE 100229) on the scaling law of the connectivity. Poisson distribution of fractures assumed by standard percolation is also in contradiction with the existence of fracture sets or the observed spatial correlation between natural fractures over scales.

In this study we first present a simple geomechanical fracture model with which we can investigate the effect of fracture spatial correlation on the network connectivity. We assume that all fracturing has happened and has achieved mechanical equilibrium which enables us to use entropy arguments and statistical mechanics to model fractures. With this, we use the realizations of correlated fracture networks in the basic methodology of the percolation and investigate the network connectivity. In particular, the simulation results show that the scaling exponents of the connectivity are different from the conventional, uncorrelated values.

We then use the field data of minerilaized fractures exposed on the southern margin of the Bristol Channel Basin to investigate the percolation behavior of the correlated fractures. We show that the connectivity predictions from the percolation approach are in agreement with the results calculated from field data with the advantage that they can be obtained very quickly. As a result this extends the applicability of percolation approach to correlated fractures which may be used for practical engineering purposes.
Multiple Slug Scaling of Linear and Pattern Laboratory Chemical Floods
Authors: Haskin Helen Kay , Davis Lorne Arthur
Published: December 2007

The screening and design of chemical flood processes requires an understanding of the effects of each chemical slug on oil recovery. The concept of volumetric linear scaling can be extended to processes involving the injection of multiple chemical slugs as long as the relative ratios of slug sizes are held constant. This allows fast development of the relation between oil recovery and slug size requirements for each chemical injected based on only a few laboratory linear floods.

Linear floods were conducted in a synthetic water-wet matrix. The multiple slug scaling approach used oil saturation distributions measured by microwave attenuation in one laboratory flood to predict accurately the tertiary residual oil saturation and tertiary oil breakthrough in another laboratory linear flood run with larger slug sizes. Oil saturation distributions at 0.11 V/Vp intervals during the flood, as well as at Sorc, were also accurately predicted.

A laboratory quarter five-spot pattern flood involving sequential injection of a small surfactant slug, a small polymer slug, and continuous drive water was run in a water-wet synthetic matrix. Linear flood oil saturation distributions were scaled to predict the oil saturation distributions in the pattern using a fixed twelve streamtube model for the flow. Details of this scaling procedure are given. Residual tertiary oil saturation, tertiary recovery, and oil saturation changes with time were predicted to within the experimental errors involved in the procedures. The observed tertiary oil breakthrough was later than predicted. Observed oil saturation distributions tended to show more oil left in the corners of the model than predicted by the scaling theory. These secondary effects and the overall behavior of the pattern flood are considered in terms of the chosen streamtube network and the assumptions of stable unit mobility flow.
Flow Assurance: Reliable and Accurate Prediction of the Viscosity of Natural Gas
Authors: Vesovic V.
Published: December 2007

Modern viscosity prediction methods have to satisfy the requirements for flow assurance and reliable reservoir characterization by demonstrably predicting accurate, reliable and internally consistent viscosity data. The best way to achieve this is by employing predictive methods based on the best available theory, simplified, just sufficiently to allow ready application and validated against a critical set of primary experimental data of proven accuracy.

The presented VW methodology is one such method, that is based on the kinetic theory of rigid spheres, modified to take into account the behavior of real fluids. It has no adjustable parameters, and requires no dense mixture viscosity data. In this work, the VW method was validated against a new set of natural gas viscosity data of very high accuracy. The experimental data were predicted with an rms deviation of the order of 0.5%-1%, commensurate with the experimental accuracy of the data. Overall, it is estimated that the VW method can predict the viscosity of natural gas within ±2% in the temperature region 260 K - 400 K and pressures up to 200 bars, with the accuracy deteriorating slightly at higher pressures and lower temperatures. It can be used to predict the viscosity of CO2-rich, sour and wet natural gas.
Interpretation of Post Deep-Acidizing Pressure Tests in a Naturally Fractured Reservoir
Authors: Bensalem Omar , Tiab Djebbar
Published: December 2007

Acidizing wells after completion or even after some period of production is a standard practice in naturally fractured reservoirs. Such a practice allows easier and faster removal of mud materials from the fractures intersecting the well. In some reservoirs, acidizing is performed deep into the formation for the purpose of enlarging the width of fissures and enhancing their interconnectivity. This results in a composite system with two zones, each having different characteristics, including storage capacity ratio, interporosity flow coefficient, and permeability. Composite systems may also result from fluid injection. High injection of fluids causes larger opening of fractures near the wellbore (due to higher pore pressure), which results in an increase of fracture permeability around the well.

In this paper the inner zone is considered to be finite, but the outer zone can be bounded or infinite. A model for a composite naturally fractured system has been developed by assuming pseudo-steady state fluid transfer from matrix to fractures, and taking into consideration the effects of: wellbore storage, near-wellbore formation damage and skin at the interface of the two zones. The loglog plots of the pressure and pressure derivative as a function of the storage capacity and permeability ratios of the two zones provide unique characteristics, which were used to derive equations for calculating the parameters of the two zones, radius of the inner zone, mechanical skin ,and skin at the interface.

From the interpretation of the loglog plots of the pressure and pressure derivative data, using Tiab's Direct Synthesis (TDS) technique, we have found that: (1) the contribution of the matrix to the flow can occur in the inner zone or the outer zone, depending on the product of the interporosity flow factor and radius of the inner zone; (2) When the ratio of the dimensionless radius of the two zones is less than ten, the naturally fractured reservoir behaves like a homogeneous system; (3) For storage capacity and permeability ratios greater than unity, the pressure derivative curve has a hump, which may appear before or after the trough; the coordinates of this maximum point may be used to calculate the permeability of the outer zone in the absence of the second radial flow line; and (4) the presence of a thin skin zone at the interface influences the starting time of the radial flow line of the outer zone. Several numerical examples are included in the paper.
Validation of History Matching Results Achieved by Multiscale Methods
Authors: Valestrand Randi , Nævdal Geir
Published: December 2007

A widely used method for finding unknown reservoir properties is estimating them as parameters through history matching. There is a risk that the parameter estimation will fail using this technique, because: A) It is an ill-posed inverse problem, and/or B) The reservoir model could contain model errors. In history matching the success of the estimation is validated by how well the data are matched, but there is a risk that the estimation has failed due to A) or B) even though the data are matched.

In this paper we present a method for identifying when the history matching estimation has failed. Moreover, the method is helpful in deciding when to stop the estimation procedure.

The validation method presented here is developed for multiscale estimation techniques and consist of the following: The objective function (measure of data-match) and the property to be estimated are predicted by analytical calculations. We then perform the estimation while comparing the development of the estimated and predicted values. How close the predicted and the estimated values are, is used to indicate success or failure.

The validation method is illustrated on two examples where we estimate the absolute permeability from reservoir production data. One of the examples is a simple 2D synthetic case while the other is a simplified 2D model generated by using a single horizontal layer from a North Sea field model.
EOR Evaluation Method for Highly Heterogeneous and Complex Reservoirs
Authors: Figuera L. , Khan K. , Quijada D. , Maestracci W.
Published: December 2007

Giant reservoirs in North of Monagas in Venezuela have been submitted to Waterflooding (since 1993) and Gas injection (since 1998) to support the oil production. currently the oil production is around 840 MBNPD. Those highly heterogeneous reservoirs are deep, with high pressure and temperature and presenting compositional fluid variation with depth. In order to maximize the reserves of these reservoirs the feasibility of applying EOR processes have been analyzed. Several existing methodologies and commercial software packages designed for the evaluation of EOR processes do not offer the aduate support for the decision making in highly heterogeneous and complex reservoirs.

An integrated methodology has been proposed to evaluate and select the possible EOR processes in the North of Monagas. The methodology is based on a combination of economical criteria, recovery improvement and risk analysis.

The methodology can be structured in three stages. In stage I, multiple analytical methodologies for the pre selection of all applicable processes are integrated. During stage II, the uncertainty associated with each pre selected process is assessed through the areal, vertical and displacement sweep efficiencies evaluation using 1D and 2D numerical simulation models. In Stage III, each process is evaluated at 3D full-field scale and a risk analysis is performed as a function of stage II results.

The proposed methodology states a structured way for the evaluation and selection of EOR processes in complex and a heterogeneous reservoir, which integrates conventional analyses, numerical simulation and risk analysis as decision tools. This paper enhances existing methodologies for the evaluation of EOR processes.
The Isenhour Unit — A Unique Polymer-Augmented Alkaline Flood
Authors: Sloat Ben , Zlomke Darrell
Published: December 2007

The Almy sands in Sublette County, Wyoming have been subjected to various volumetric sweep improvement techniques since September, 1969. This paper describes the first field wide effort to reduce residual oil saturation in the swept area.

Initially, a series of crude oil - alkaline agent screening tests were run to select, on the basis of interfacial tension reduction (IFT), the most cost effective alkaline agent. Follow up core tests showed that a combination of soda ash (Na2CO3) and anionic polymer would be effective in reducing oil saturations from 22 to 17 percent pore volume. The core tests also demonstrated that a properly prepared alkaline solution could be injected into the high clay content Almy. On the basis of these test results and ten years of experience injecting clay stabilizers, anionic polymers and wettability alteration products, the decision was made to go from the start with a total oil recovery program.

The original plant design was modified to accommodate the requirements for adding one half million pounds of Na2CO3 in less than a year. This involved installing a second dry solids feed system, interchangeable with the regular polymer unit. Storage capacity at the plant site was increased to 50,000 pounds of dry product and on the Na2CO3 unit a second 100 gallon stainless steel solution tank was put in series with the regular mix tank. Operating people designed and built a rugged, inexpensive product handling system that allows the plant operator to service both feed units in less than one hour a day.

Input side control tests include pH, O2, PO4, turbidity, screen factor and viscosity. Hall Plots are the primary monitor of injection well conditions with step rate tests and pressure fall-off measurements used as back up.

Producing wells are tested once a month. Data is plotted on a time-rate basis as well as graphed in the form of water-oil ratio (WOR) vs. cumulative oil recovery.

Produced water samples are checked for pH, chloride, tracers (thiocyanate and nitrate) and polymer breakthru. These results are also posted on the individual producing well graphs.

Although only in its third year of operation, the project is far enough along to conclude the following:

It is practical and profitable to employ, at the same time, techniques that will improve sweep and lower residual oil saturation. Selecting a "Total Oil Recovery" process and starting it early greatly simplifies plant design. EOR processes requiring fresh water should be started before breakthru to lower costs and lessen the problems related to lifting, treating and reuse or disposal of produced water.
Gravity Segregation in Gas-Injection IOR
Authors: Rossen W. R. , Shen C.
Published: December 2007

This paper presents a survey of simple methods for estimating vertical sweep efficiency in improved oil recovery (IOR) by gas injection.

A useful model for gravity override in gas IOR is that of Stone and Jenkins (SPE 11130, 12632), which applies to simultaneous water-gas injection into a homogeneous reservoir. Their equations for the distance to complete segregation are rigorously correct as long as the usual assumptions of fractional-flow theory apply. Their model implies that the volume swept by gas at given injection rate is approximately the same for vertical and horizontal wells, but the injection pressure does depend on well geometry and injection interval. For a given well geometry, the distance gas can travel before segregation depends directly on injection pressure. Thus, if injection pressure is limited, it is crucial to choose an injection profile that maximizes injectivity.

Recently, Stone (SPE 91724) suggested a new method of injection: gas and water injected simultaneously but separately, with water injected higher in the interval than gas. At fixed total injection rate, injection of water above gas gives deeper penetration before complete segregation than does coinjection in two-dimensional modeling and simulations. Whether injecting water above gas or both together, using only a portion of the injection interval reduces injectivity without affecting the distance to the point of segregation.

These results apply to both gas and foam IOR as long as gas and water are injected simultaneously or in separate, small slugs.
The MEG (Mono Ethylene) Injection Gas Dehydration Process Evaluation for the Margarita Field Development
Authors: Vergara Contreras Moises Alfredo , Foucart Nicolas
Published: December 2007

The objective of the study is to select the gas dehydration process system within the Margarita Field Development Project based on "MEG (MONO ETHYLENE) Injection with Mechanical Refrigeration" and compare it with the "Glycol Dehydration Process System", from the technological and economical point of view.

The dehydration process based on TEG is the most common process for natural gas dehydration; it is an efficient technology and its operation is very well known.

In order to reduce the CAPEX and OPEX of the Project, the operator has studied potential process options. One way to optimize the gas dehydration process is by simplifying and combining it with other processes, which is the case when considering the combined MEG injection with mechanical refrigeration, a common practice in the Industry.

The scope of this report covers:

○ Estimate of the downstream and utility equipments as required (glycol loss, glycol rate recirculation, electrical requirements, etc) ○ Cost Estimate (OPEX / CAPEX). ○ Explanation of uncertainties and risks that may be associated in applying the dehydration process on this particular application, and steps (if required) to eliminate those uncertainties. ○ To take experience of similar plants with similar requirement.

The MEG Injection together with a Dew Point Plant is able to dehydrate the natural gas, because the chiller unit operates at low temperatures and it permits the water content of the gas to be condensed and removed in "cold separation", but this process requires inhibitor injection in order to avoid hydration formation, being glycol the usual inhibitor. Removing the Contactor Tower and changing TEG by MEG has little impact in the Dew Point Plant design. The additional power required in the propane compressor is compensated in the glycol pump which is lower power consumption because the MEG injection rate is lower than the TEG one.

The different aspects evaluated between MEG Injection and Contactor Tower with TEG, are favorable toward the MEG Injection as:

○ CAPEX: FOB Cost. ○ MEG Injection saves MEG regeneration unit which is smaller and lighter. ○ Elimination of TEG contactors will simplify the plant, reduce installation cost and avoid large heavy vessels with transportation constraints. ○ MEG injection is easier to regenerate than TEG and alleviates environmental issues with BTEX emission.

After taking in consideration all the points in favor of the MEG Injection, it is recommended to install it in the Gas Treatment Plant.
Anisotropic PP and PSv Prestack Depth Migration of 4C (OBC) Seismic Data, Pamberi, Offshore Trinidad
Authors: Johns T. D. , Vito C. , Sarmiento R.
Published: December 2007

In November 2004, EOG Resources acquired an ocean-bottom cable (OBC) 4C swath survey across the Pamberi-1 well location in the Lower Reverse L block of the Columbus basin, eastern offshore Trinidad. The purpose of the 4C test survey was to evaluate the potential of long-offset multicomponent technology for resolving lithology and stratigraphic detail in an area perturbed by shallow gas, overpressure and illumination shadows from normal regional faults and major anticlinal ridge trends acting as pressure seals. The motivation from EOG for attempting this was because a conventional 3D towed-streamer survey acquired the previous year failed to adequately image the target reflectors comprising the reservoir under the main growth fault.

Details of the P- and PSv-wave processing of this dataset through anisotropic prestack time migration were previously described (Johns et al., 2006) in which it was demonstrated there existed a qualitative correlation between derived parameters and attributes from P and Sv anisotropic migration velocities and known regional geology. This observation was quite remarkable considering only a limited effort to constrain or validate parameters (in this case, velocities to the Pamberi-1 well checkshots) was performed. Under the "Future work" section of the previous publication, it was suggested that further data quality enhancement in preparation for more quantitative rock property classification, calibrated to wells, could only be achieved after prestack depth imaging.

In this paper, we present precisely that next phase in the 4C processing, advancing the P- and PSv-wave data through anisotropic prestack depth migration, using cell-based tomography with a top-down pseudo layer-stripping approach. The Pamberi-1 well information was used to constrain the anisotropy in the shallow section, with the deeper, spatial trend away from the proximity of the well determined from the anisotropy derived previously in the time processing.

Prior to proceeding with the anisotropic depth imaging, the magnitude of shear splitting (or, birefringence) from the presence of azimuthal anisotropy (HTI) is first examined to assess its potential impact on the radial rotated P-S signal. The shear-wave splitting analysis revealed a principal angle of polarization that was closely aligned with the regional stress direction delineated by the major faults blocks acting as pressure seals.
Technical Feasibility of Chemical Flooding in California Reservoirs
Authors: Holm Leroy W.
Published: December 2007

A study of the applicability of chemical flooding to California reservoirs revealed a number of facts that may not be apparent to everyone. The five chemical flooding processes reviewed in this paper are carbon dioxide, micellar-polymer, polymer, caustic and hydrocarbon miscible.

In terms of enhanced oil recovery, California is by far the leading State in total oil production, number of projects, money invested, etc.(1) The EOR projects are mainly thermal, not chemical, but they account for about 75% of total EOR production in the U.S. (Fig. 1.). These EOR projects have helped California to maintain its production and reserves during the past ten years while other major oil producing states (Texas, Louisiansu Oklahoma) have experienced substantial declines.(2) (Figs. 2 and 3).

Although California is thought of primarily as a source of heavy, low gravity crude oil with potential for only thermal processes, over one half of the 435 California reservoirs on which DOE has crude oil data(3) contain oils with gravities of 25° API or higher and viscosities of less than 20 cp. These reservoirs include sands in the large Wilmington, Belridge, Coalinga, Ventura and Midway Sunset fields. Based on crude oil properties, these reservoirs are candidates for all of the chemical flooding processes (miscible and non miscible). And, some of the largest of the chemical flood projects in the U.S. are already underway in California in the Wilmington, Huntington Beach, Coalihga and Orcutt Hills fields. (Table 1).
Field Performance Analysis of Micellar Polymer Pilot Flood
Authors: Aguey Omar Jose
Published: December 2007

This paper describes field operations with attendant problems encountered during a micellar polymer flood process in the Hxa sand of the Wilmington Field, California.

Problems encountered include completion techniques, extreme corrosion, emulsions of produced fluids, and field handling of polymer.

The micellar polymer flood described here is Marathon Oil Company's Maraflood (TM) process and was designed by Marathon after much laboratory and field testing. The project was co-sponsored with D.O.E. and the City of Long Beach with the goal of establishing a tertiary oil recovery technique applicable to unconsolidated oil sands typical of the California region.

The test pattern selected, after conducting several computer model studies, is a staggered line drive consisting of four injection wells and six producing wells, with all injectors backed up by a North South trending fault. The sand selected for this pilot is located in the watered-out area of the Hxa sand of the Upper Terminal V-B Pool. Selection was made because of sand thickness, uniform sand body, good permeability, and because it was a watered out area which would facilitate the project evaluation.

The pilot project includes a total oil sand volume of 596 acre-feet underlying an area of about ten acres ith an average net sand thickness of 58 feet (17.7m). The permeability to air is about 400 md. The residual oil saturation after water flooding is estimated to be 38%. Recovery to date is estimated to be 38% of the 445 M barrels (70749 m3) of oil in place at the beginning of this project. The incremental oil recovery is expected to be 176,000 barrels (27982 m3) at abandomnent time.

The importance of this test is not only to determine he validity of the process in watered out areas of the vast Wilmington Field, but to determine and overcome field operating problems associated with a micellar polymer flood.
New Integrated Applications Using T1 and T2 Modes of Magnetic Resonance in Tight Gas Reservoirs: A Case Study From Northern Mexico
Authors: Monroy Ayala Norberto , Muñoz Rogelio , Rico Raul , Palacios Cesar , Torne Juan Pablo , Leuro Jorge , Fam Maged
Published: December 2007

Petrophysical evaluation of the tight gas reservoirs in northern Mexico presents challenges for identifying overpressured gas zones when applying conventional techniques in laminated and fine grain sand zones. This paper presents case histories in which the magnetic resonance technology was used in its new T1 mode and describes the advantages of this new logging mode over the conventional T2 mode in gas reservoirs. The paper highlights the integration of all available petrophysical data for a particular field. This integration model compares the irreducible water saturation between the newly developed models, based on magnetic resonance data after its calibration to core, conventional logs, and production tests. Our integrated approach was used to analyze the data from different wells drilled in the field and to determine the best petrophysical parameters for any interpretation. The approach used was focused on identifying the best zones to be further evaluated, considering the different responses of all available log data from each well in the field.

Permeability was derived from the Coates model using the magnetic resonance data after its calibration to cores. Results were then compared to actual production. For those wells in which only standard MRI logging information was available, the model was used to calculate the permeability and compare it to actual cores. Production test results were also compared to the evaluation prognosis and used to fine tune the interpretation model. The model was then used in other wells in the area for which few conventional log data were acquired.

The integrated approach used with the new MRI acquisition technique benefits the operators by helping them to better evaluate and produce laminated tight gas reservoirs. The methods developed helps with making the right decisions regarding the need to acquire additional log data, with defining intervals for testing, and determining the size of the required hydraulic fracturing for production.
A Second-Order Mimetic Approach for Tracer Flow in Oil Reservoirs
Authors: Guevara-Jordan J. M. , Arteaga-Arispe J.
Published: December 2007

A new mimetic method for solving tracer flow equations in oil reservoirs is presented. This mimetic method is a formal extension and an improved version of standard finite differences schemes and it has three main advantages. First, its grid is a hybrid version of point center and point distributed grids, so the new method does not require ghost points in its formulation and implementation. Second, boundary conditions approximations achieves same order of convergence as inner nodes, it is well known that standard finite difference schemes convergence rate deteriorates at boundaries. Third, the new scheme satisfies Green-Gauss-Stokes identity at the discrete level, which guarantee that the scheme is fully conservative and represents correctly the physics properties of the problem. The new scheme was implemented to solve tracer flow equations in a reservoir and it was tested in a set of five spot problems. Numerical results show that the new scheme produces better approximations than standard finite difference simulators on coarse grids.
Production Optimization Using the Capillary Technology in the Loma La Lata Field
Authors: Cabral P. , Giérega C. R. , Costanza P. , Suriano A. A.
Published: December 2007

Ever since its discovery in 1977, the Loma La Lata field, located in the Neuquén basin, has been considered one of the most important gas fields in South America.

During the last decade, the progressive reduction in the reservoir pressure has led to successive changes in the field's operation conditions: from high to medium pressure, and, most recently, to low pressure.

As the reservoir pressure depletes, the subsequent reductions in the gas velocities bring about changes in the flow regimes and the increasing liquid flow rates. These liquids produced at the wellbore and/or generated by vapor condensation through the production string, contribute to increase the pressure drop along the tubing as well as the flowing bottomhole pressure, and will eventually reduce or prevent production.

In most cases, not only does liquid loading arise as a consequence of these changes in operation conditions, but also other production problems such as mineral scales and organic deposits, and the difficulty to implement corrosion prevention conventional batch treatment programs aimed at extending the life of the production strings.

In addition to the above, the increasing hydrocarbon demand, Argentina's energy policy and economical restrictions are also matter of relevance when it comes to implementing conventional solutions that imply several shutdown hours per treated well.

The aforementioned problems have encouraged the operating and services companies to search for technological alternatives providing not only technical solutions but also economical benefits.

After one year since a novel capillary string system that allows for the injection of chemical products, and/or the deployment of special devices such as memory gauges, at the desired depth was introduced in the country, the results obtained in several tests show a very promising future.

This paper summarizes the first-year results achieved using the capillary string technology as a tool for production enhancement and optimization in the Loma La Lata field.
Static and Dynamic Models of Formation Water in Sincor Area, Orinoco Belt, Venezuela
Authors: Marcos J. , Pardo E. , Casas J. , Delgado D. , Rondon M. , Exposito M. , Zerpa L. , Ichbia J. , Bellorini J.
Published: December 2007

Sincor is a strategic association between PDVSA, Total and Statoil, committed to the production, upgrading and commercialization of extra heavy oil from an area covering over 325 Km2 in the Orinoco Belt (Figure 1).

The Sincor area is composed of a series of stacked unconsolidated sand-shale reservoirs with good petrophysical properties. The depositional system can be divided in two main parts, Deltaic and Fluvial. Fluvial sands, mainly stacked braided channels, represent the bottom part of the reservoir. Deltaic sands go from distributary channel and mouth bar to point bar and crevasse splay.

Drilling of vertical observation wells and a testing campaign started at the end of 1999. In well tests, anomalies in water salinity values were observed: an aquifer salinity of 2300 ppm, while some wells produced water at 15000 ppm. At that time, high values were considered measurement problems.

In 2001, the first horizontal producers started to cut water with similar high values to those observed in some well tests. Since then a multidisciplinary study was launched aiming at defining and characterizing all water sources using well tests (15 vertical wells) and water production data (150 horizontal wells). This information has then been integrated with geological interpretation and reservoir characterization.

In this paper a static model is developed using well test information from the area. The model explains why different ranges of water salinities were observed in the oil and water zones. This model was corroborated qualitatively with log information.

Dynamic data confirmed and detailed further the initial model. An exponential decrease of water salinity is generally observed with increasing water production or water cut. This phenomenon is explained by probable water influx in the form of fingering from the low salinity aquifer continously displacing high salinity formation water. The exponential curve shape would depend on the tortuosity and length of the path between the water and the produced oil zones.

Static and dynamic data are consistent and confirm our model of water production mechanism observed in the field.
Enhanced Mass Transfer of CO2 Into Water and Oil by Natural Convection
Authors: Farajzadeh R. , Delil H. A. , Zitha P. L. J. , Bruining J.
Published: December 2007

Global warming has increased interest in quantification of the dissolution of CO2 in (sub)-surface water. CO2 is present above the surface water. Dissolution of CO2 into water (or oil) causes a density increase, with respect to pure water (or oil). This density effect causes natural convection, which enhances the mass transfer rate across the interface. This article describes a series of experiments performed in a cylindrical PVT-cell, where a fixed volume of CO2 gas was brought into contact with a column of distilled water. The results show that the mass transfer rate across the interface is much faster than predicted by Fick's law. This mass transfer rate increases with increasing initial gas pressure. However, in the long term the mass transfer rate is controlled by diffusion alone. The long term behavior, therefore, allows the determination of the diffusion coefficient. Its value agrees with values presented in the literature. A similar mass transfer behavior was observed for the experiments with an oil phase (n-C10 and n-C16). Therefore analogous experiments using oil instead of water are valuable for enhanced oil recovery projects.

A theoretical interpretation of the observed effects has been proposed, based on diffusion and natural convection phenomena. The Rayleigh number is of the order of one million whereas the Schmidt number is of the order of five hundred. The ensuing equations have been solved numerically, using the finite volume approach. There is qualitative agreement between the experiment and the numerical results and similar to the experiments the mass transfer becomes diffusion like in the long term.
An Approach to Optimum Facility Siting
Authors: Mathur Anil , Haire William Mullen , Earhart James W. , Weaver Susan E.
Published: December 2007

This paper describes a heuristic approach to Production Facility siting and optimal pipeline routing to connect wells to Production Facilities. The pipe sizes for the production, lift gas and water injection systems were calculated and included in the optimization. Production Facility siting, based on production lines alone, is not optimal.