bluuebunny/crossref_metadata_2025_split huggingface dataset:
Recovery of Heavy Matrix Oil by Capillary Imbibition in Naturally Fractured Reservoirs
Authors: Babadagli Tayfun 
Published: December 2007

Abstract
If matrix is water wet and enough amount of water is supplied in fractures, capillary imbibition becomes the governing recovery mechanism in naturally fractured reservoirs. When the matrix contains heavy oil, however, this process becomes highly ineffective due to slow recovery rate and high residual oil saturation. Additional methods, other than waterflooding, such as injection of surfactant solution, polymer solution or hot water should be considered to increase the effectiveness of the capillary imbibition recovery of heavy matrix oil.
This paper includes the results and analysis of the laboratory scale experimentation of these three methods. Experiments are conducted on Berea Sandstones (water-wet sample) using heavy oil samples with the viscosities ranging between 185 and 630 cP. Carbonate cores (oil-wet limestone samples) were also used with light oil samples for comparison purpose. Different boundary conditions are created using epoxy coating. Based on boundary conditions, co- or counter-current type capillary imbibition takes place. Performances of the three methods are compared in terms of ultimate recovery and recovery rate. It is observed that all three methods yield higher and faster capillary imbibition recovery compared to waterflooding. The contribution of chemical additives and high temperature of water becomes more pronounced as the viscosity of oil increases. This contribution is more prominent on ultimate recovery than the recovery rate, especially for chemical solution cases.
Two-fluid Mixing Enhancement by Using a Static Turbulence Generator
Authors: Ortega P. , McGrath G. , Rojas L. 
Published: December 2007

ABSTRACT
The numerical simulation of a static T-type mixer for turbulent mixing of miscible liquids is reported. The simulation was carried out using CFX, a commercial computational fluid dynamic simulator. The effect of mixing intensification caused by turbulence generators placed downstream of the injection point of the Tee was evaluated in terms of reduction in mixing length for a given mixture quality, uniformity of turbulence intensity and efficiency of energy conversion to useful mixing energy.
The mixing quality for an intensified and conventional T-type mixer was compared, and the turbulence generator geometry was optimized. Main stream Reynolds numbers between 50000 and 100000 were considered for additive volume ratios in the range 0.1 – 10%. Selected simulations were validated with experimental data available in the literature for conventional smooth T-type mixers (no ribs).
Results were in good agreement with experimental correlations available at high Reynolds numbers.
Simulations demonstrated that mixing enhancement was efficient with turbulence generators, extending the Reynolds number range for which compact, low pressure-drop devices may be used for intense mixing. The optimum geometry for turbulence generators was evaluated using criteria based on energetic and spatial efficiency and in all cases the simple Tee was used as the point of reference.
Finally, practical design correlations are presented to enable the mixing quality of two miscible streams to be estimated for a simple Tee with and without additional turbulence generators over a range of Reynolds numbers and injection conditions.
Optimal Exploitation Scheme in MFB-5 Reservoir
Authors: Blanco M. , Rodríguez T. , Crespo J. , Granado A. , de Rojas B. 
Published: December 2007

Abstract
In order to contribute with the development of Orinoco Belt reservoirs, a simulation model was created to be used on the extra heavy crude oil reservoir MFB-5, located in Bare block, Hamaca area. So far, this reservoir has produced about 1% of oil in place, estimated in 216 MMSTB. Besides, it has an associated aquifer, which generates high water cuts caused by channeling. This situation motivate the study of different exploitation strategies to obtain the most profitable oil recovery. At present reservoir conditions and under primary recovery, there is still a 14% of total recoverable oil (28 MMSTB). The main objective of this work was to obtain the highest oil recovery with the lowest number of new locations, and with the most favorable well production conditions for this reservoir. An economical analysis was performed for each scheme and the result was that the best technical and income-producing exploitation strategy, would recover 15% of OOIP in 20 years, which would exceed recoverable oil in place in 6% if the current 9 active wells are maintained producing under the present strategy.
Fracturing with Crosslinked Methanol in Water-Sensitive Formations
Authors: Malone Mark R. 
Published: December 2007

Abstract
The use of methanol in fracturing is not new technology. Its origin and application in hydraulic fracturing can be traced back to the 1960's. However, advances in fracturing fluid chemistry and breaker technology have improved dramatically creating new systems such as crosslinked methanol, the subject of this paper. Methanol has been utilized in the well stimulation industry for many years to take advantage of its low surface tension properties and miscibility with various formation fluids. This paper will discuss advances in crosslinked methanol system technology, system compatabilities, field application and practical safety precautions. The fluid system rheological properties and proper breaker application will be discussed as well.
In recent years, the industry has become more aware of the challenges associated with formations recognized as "water sensitive". These issues can be associated with mobile and swelling clays, or undersaturation of the formation, otherwise known as aqueous phase trapping. The paper will discuss these issues as they pertain to proper fluid selection and more specifically, the selection of crosslinked methanol as a fracturing fluid.
Formation properties of zones treated with crosslinked methanol will be presented as well as post fracture treatment results.
Changes in the Performance of Texas Gas Wells
Authors: Swindell Gary S. 
Published: December 2007

Abstract
Much recent attention has been recently given to depletion of U.S. natural gas reserves, particularly since many forecasts predict a 30 TCF annual gas market. A comprehensive look at the way initial production, decline rates, and reserves have changed over the last 30 years in Texas, the source of 1/3 of the country’s natural gas, leads to concern about whether current drilling activity will be able to maintain the current supply, much less increase gas production 1.
The decline rates in new Texas gas wells have changed from about 20% in the first year for wells drilled in the 1970’s and 1980’s, to more than 55% for wells drilled in 1998 and 1999. At the same time, the contribution to the state’s supply from new wells has sharply increased from 8% of the state’s supply to more than 15%. Although the initial production rates from an average well have actually improved from a low of 15 MMCF per month in the early 1980’s, to 44 MMCF per month in 1999 due to improved completion technology and horizontal drilling, the combined effects of fewer completions and high decline rates suggests that a decrease in Texas’ production capacity may occur in the near future. Drilling above the current activity will be necessary to sustain the state’s gas production.
Normalized rate vs. time curves were developed for each year since 1970 to obtain initial rates and decline profiles. The curves were extrapolated to an estimated ultimate recovery, changing from 6 BCF per well in the early 1970’s to 1 BCF per well in the late 1990’s.
New Approach to CO2 Flood: Soak Alternating Gas
Authors: Murray Malcolm D. , Frailey Scott M. , Lawal Akanni S. 
Published: December 2007

AbstractTo date, field wide CO2 flooding is continuous or WAG injection processes. In individual wells a huff’n’puff scheme has been used where CO2 is injected into a well followed by a shut-in period; after a predetermined time, the well is produced. Each of these methods have practical, technical, and economical limitations. This paper describes a new CO2 injection method that combines all three of these methods but excludes water injection.Continuous CO2 may be optimal in reservoirs that are not conducive to water injection and do not have CO2 mobility control problems such as early breakthrough. However, continuous CO2 requires a large initial CO2 volume that may be unavailable and relatively expensive. WAG is very common with variations of different ratios of water to CO2 volumes and tapered ratios. WAG reduces mobility problems and thereby improves areal sweep efficiency; CO2 purchase expenses may be lower due to the requirement of lower CO2 volumes. Unfortunately, water injectivity following CO2 injection may decrease, and the water increases lift and water handling expenses. Huff’n’puff is effective similar to a near wellbore stimulation, but may not realize the benefits of a full field injection program. Also, this adds the complication of injection and production capabilities required in the same well. This may be impossible for some wells on artificial lift.The proposed method is to inject CO2 and shut in the well similar to the huff and puff, but instead of producing the well inject CO2 again. This process is a cyclic process like WAG, and shares the variables of the duration and volume of CO2 injection and the duration of the shut-in period. This method eliminates injectivity and production expenses associated with water. Mobility is controlled by near wellbore achievement of miscibility by the increase in mass transfer between the CO2 and oil during the shut-in portion of the cycle; i.e. a smaller portion of the reservoir has relatively low viscosity, injected CO2 due to miscibility between oil and gas occurring nearer the injection well.
Strategies for Reducing Oil Field Electric Power Costs in a Deregulated Market
Authors: Stiles Robert F. , Slezak M. Steven 
Published: December 2007

Abstract
The cost of electricity is one of the single largest items associated with oil and gas production. This cost however tends to be overlooked relative to other production costs, due to the regulated nature of the utilities combined with its specialized and non-core technical requirements. In spite of this, several studies and strategies over the years have looked at ways of reducing this cost component with meaningful results. Many of these strategies consist of structuring loads and designing equipment to take advantage of the utilities regulated rate structure. As the electricity industry in the US moves towards deregulation, these rate structures will no longer exist and in their place will be contracts negotiated on a free market basis between the user and supplier(s) of electricity.
In the upcoming deregulated electricity market, three key strategies are available to effectively manage oilfield power costs; 1) real time monitoring and control of the electrical load 2) in-field generation of electricity and 3) negotiation of an integrated power supply agreement. Because electricity is the ultimate just-in-time product, prices vary greatly depending upon when the power is consumed. The strategies listed above allow for the user to proactively structure their power supply systems to address the fundamental volatility of the real price of electricity. The effect is to strip out the historic premium that is paid to the utility to handle the natural volatility of electricity prices by blending load shifting, internal generation and market purchases.
This paper examines different scenarios where the above strategies are proposed and makes estimates for potential cost savings. These solutions utilize existing technology applied to the changing market environment and therefore focus on economic justification as opposed to technology verification. In one such case the pumping intervals for a collection of wells is adjusted using real time power prices combined with remote operations. This has the effect of reducing the total cost of the electricity consumed per barrel of production while only marginally reducing the actual number of barrels produced.
Pressure Fall-Off Analysis in Water Injection Wells Using the Tiab's Direct Synthesis Technique
Authors: Jokhio Sarfraz A. , Tiab Djebbar , Abdessalam Hadjaz , Escobar Freddy H. 
Published: December 2007

Abstract
Numerous waterflooding projects are under way throughout the world for increased recovery. Water injection tests of oil zones are frequently undertaken during the planning phase of waterfloods. Analysis of the bottomhole pressure data recorded during these tests not only provides similar information to that obtained from production tests concerning the well and the reservoir characteristics but also allows the mobility ratio between the injected and resident fluids to be determined.
Conventionally, pressure fall-off test data is analyzed using semilog plot of bottomhole pressure versus time. This paper is the extension of the Tiab’s Direct Synthesis Technique10-15 to pressure injection and Fall-off tests in water injection wells.
Direct synthesis is a transient pressure analysis technique10- 15, which uses log-log plot of pressure and pressure derivative vs. time. Thus, different straight line portions indicating different flow regions are directly analyzed. Direct synthesis is very useful in conditions of short and early time pressure data missing tests. It also verifies the results since it uses more than one equation for the estimation of reservoir parameters such as permeability, wellbore storage coefficient, and skin factor.
Finally, field examples of pressure falloff analysis are presented to illustrate use the direct synthesis and results are compared with those from type curves and conventional semilog analysis.
Optimizing Field Performance Using Reservoir Modeling and Simulation
Authors: Naguib Mohamed A. , Aziz Khaled A. , Hussein Ahmed 
Published: December 2007

Abstract
Ras Budran field is a massive Nubian sandstone reservoir compartmentalized by major faults acting as partial barriers. Vertical communication is impeded by hydraulically sealing shale layers in the development of three main pressure regimes. A combined water injection and aquifer support the pressure. Pre-mature water breakthrough has been occurred in the middle of oil leg, which in turn limit the corrective action of the isolation of the watered out zones.
3D- geological and reservoir simulation model was constructed, based upon new reservoir characterization with the objective of improving the vertical definitions within the reservoir. The reservoir properties generated by deterministic interpretation for the new micro-zones.
This paper presents the approach taken to match 17 years of production data in particular, via aquifer definition and fault communication.
The history-matched model was then used to confidently check the production and injection well pattern and performance. The matched model then used to investigate the viability of infill wells to improve drainage pattern and sweep efficiency meanwhile increasing ultimate recovery.
The Role of 3-D Seismic in a Challenging Horizontal Drilling Environment: The Cerro Negro Experience
Authors: Zubizarreta J. , Robertson G. , Adame J. 
Published: December 2007

Abstract
Cerro Negro is a heavy oil strategic association, located in the eastern portion of the ‘Orinoco Heavy Oil Belt’, of Venezuela. The 700-feet thick reservoir sands are assigned to the early and middle Miocene Morichal Member of the Oficina Formation. The Morichal is a transgressive fluvial to estuarine and marine sedimentary sequence, and is informally divided in to Lower, Middle and Upper units. Sands were deposited in valley fairways and show a high degree of lateral variability. This stratigraphic variability has an important impact on the seismic response. This reponse, or acoustic impedance, is directly proportional to the density and velocity differences of the lithological units. Most of the seismic impedance contrast in Cerro Negro is caused by ‘tuning effects’, due to thickness variations of the reservoir units. The use of the seismic data was instrumental for deciphering the complex relationships in the reservoir, and designing a 121 horizontal well drilling program. The integrated team approach, and the use all the well and seismic data available, was critical in the success of the first phase of the project.
Analyzing Flowing Production Data with Standard Pressure Transient Methods
Authors: Hager C. J. , Jones J. R. 
Published: December 2007

Abstract
Interpretation of pressure transient data using the derivative curve has proven to be an effective method for quantifying and qualifying well/reservoir information. Analyzing pressure response data affected by multiple rate changes is well understood and readily done using this standard approach. Daily production data (Time-Rate-Pressure) adheres to the same physics and theoretical description as standard multi-rate drawdown data. Therefore, this form of data can be analyzed in a similar manner.
This paper shows that the multiple flow rates and pressures forming production data can be transformed into an equivalent single rate data set for direct analysis using standard methods based on the associated derivative curve. The transformation requires nothing more than careful superposition and the calculation of the normal radial flow derivative curve. We show that this approach avoids two of the biggest difficulties with using rate-time type curves for the analysis of production data: the lack of methods for determining the regions in the data representing the proper flow regimes to apply the appropriate analysis, and the calculation of the correct pseudoequivalent production time function. A method for incorporating a derivative smoothing technique is included to improve the ability to interpret field data, which can often be erratic and difficult to analyze. After a brief presentation of the necessary theory, the applicability of this approach using both simulated examples and field data will be demonstrated.
Pressure Analysis for a Well Intersected by a Hydraulic Fracture with Multiple Segments
Authors: Escobar Freddy H. , Tiab Djebbar , Jokhio Sarfraz A. 
Published: December 2007

Abstract
This paper investigates the effect of multi-branched hydraulic fracture on transient pressure response of the well. Pressure transient analysis usually considers the fracture to be singleplanar surface in the rock. However, hydraulic fractures may have branches or segments which are originated at different positions along the main fracture or even starting at the wellbore (far field or near the wellbore).
A mathematical formulation intended to simulate certain fracture segmentation pattern in defferent directions is proposed assuming constant width and infinite conductivity fracture. The effect of conductivity contrast between the fractures has also been studied. The solution was obtained numerically by using an implicit formulation with the finite-difference method.
It was observed that the pressure response of a vertically fractured well with segmented fractures is very similar to the one of a well with a single fracture. A well with multiple fracture reflects the pressure behavior of a single fracture with an average conductivity. Therefore, the branched fracture does not show any recognizable/identifiable pattern in neither the pressure derivative nor the second pressure derivative curves.
Thus, it is implied that the fracture communication amongst branched network is instantaneous for infinite-conductivity fractures. Therefore, from well test data it is not possible to detect the presence of fracture branches in a reservoir. However, when the branched fracture has less conductivity than the main fracture body, the pressure response behaves like that of a well with single fracture of an average conductivity. The observed pressure pattern is the same for the case of equal fracture conductivities but a higher pressure drop is observed as the branched fracture conductivity is reduced.
Development and Application of a New Roller Cone Bit with Optimized Tooth Orientation
Authors: Chen S. L. , Dahlem Jim , Dennis John 
Published: December 2007

Abstract
Based on computer drilling simulation results, a new, unique roller cone bit has been developed1. All the teeth on this new bit are oriented optimally such that the leading face of the elongated crest of a tooth is perpendicular to its trajectory during interaction with a formation. This paper describes the computer model, the calculation procedure for determining the trajectories of the teeth, and the method for designing the new bit. Laboratory and field tests have shown that the new bits drill up to 25% faster and longer than the same type of bits with conventional tooth design.
Heavy Oil Recovery in Potiguar Basin, Brazil: Steamflooding from Field Pilot Testing to Commercial Application
Authors: Mezzomo Roberto F. , Dutra Tarcilio V. , de Miranda-Filho Daniel N. , de Paula Armando L. , Cursino Delson F. S. 
Published: December 2007

Abstract
Northeastern Brazil, in the fields of Fazenda Belém, Estreito and Alto do Rodrigues. Shortly after discovery, they were stepwise and successfully put into production through steam cycling. However, upon trying to convert this operation to steamflooding via two field pilots in selected areas of Fazenda Belém and Alto do Rodrigues, where cycling had reached the economic limit, the results left much to be desired. The operation was suspended and production maintained by the original steamcycling program by expanding it into new areas of the fields.
Based on the fact that the two steamflooding field pilot attempts were on patterns of 5 and 2½ acres, respectively, it was thought that reservoir heterogeneity, among other issues, could be responsible for the two consecutive failures. Consequently, a third pilot was decided upon, this time in a specific area of Estreito. Some 1,600 MMB of 15-16ºAPI OOIP were discovered in the early eighties, onshore Potiguar Basin, field. New wells were drilled for this purpose, defining four adjacent and inverted nine-spot patterns of 1¼ acre each.
It was the year of 1993, when a project was approved in the portfolio of PRAVAP-Petrobras Strategic Advanced Oil Recovery Program, to design and implement the Estreito steamflooding pilot test, together with other related lines of research focused on the heavy oil accumulations in Potiguar Basin. Five years, 32,000 man-hours, and US$2.3 million later, the results were so encouraging that prompted the decision by the Operational Unit to initiate the corresponding study to scale-up the pilot test not only to the entire Estreito field but also to the neighboring, Alto do Rodrigues. In addition, this enterprise took into consideration the installation of a gas fired thermoelectric plant for the co-generation of steam and electricity, as to enhance the economic feasibility potential.
This paper presents the results of the PRAVAP project, as well as the production forecasts for the ongoing effort to expand the steamfloding operation to the commercial scale in those two fields.