bluuebunny/crossref_metadata_2025_split huggingface dataset:
Frontiers of Formation Evaluation and Petrophysics; Present and Future Technologies
Authors: AlRuwaili Saleh B. 
Published: December 2007

Abstract
In anticipation of important technological advancements, during the 21st century, it is worthwhile discussing the frontiers of the current formation evaluation and petrophysics. Today, formation evaluation has limits, dictated by the available logging technologies, core-analysis expertise, petrophysical models and interpretation methods. Technological advancements in logging measurements, core-analysis or petrophysical interpretations can contribute to widening the horizon of formation evaluation and magnifying its value in the oil and gas business.
Logging technologies and services currently provided have various limitations. The resolution of the logging tools has not come below one foot. The depth-of-investigation of almost all the logging tools has not exceeded a couple of feet into the formation. Data acquisition in most of the logging tools has limited speed. Logging technologies have not yet enabled direct and continous measurements of formation permeability and electrical properties.
Similarly, there are some limitations in the petrophysical models and interpretation methods available. Deterministic petrophysics has limited capability in characterizing minerals in the formation. Non-deterministic, or probabilistic petrophysics, has prediction capability to some minerals, yet its prediction of formation minerals is non-unique. Insufficient mineralogical-description of formation lithology can introduce inaccuracy in the calculation of formation-porosity. Inadequate characterization of rocks and their types can have negative effects on estimating water-saturation and permeability in the formation. Technology and expertise enabling factual representation of formation parameters are essential for obtaining state-of-the-art formation evaluation.
Core data is considered the ground truth and can have a corner-stone role in formation evaluation. Different core-analysis laboratories could give different measurements of the same attributes from the same core. Standardization of procedures among core-analysis laboratories is highly needed for better formation evaluation and petrophysics.
Laboratory Study on Precipitation of Calcium Sulphate in Berea Sandstone Cores
Authors: Abu-Khamsin S. A. , Ahmad S. J. 
Published: December 2007

Abstract
Scale deposition is one of the most serious oil field problems that inflict water injection systems primarily when two incompatible waters are involved. Mixing of these waters could cause precipitation of CaSO4, BaSO4 and/or SrSO4.
To generate reaction kinetics data, the rate of calcium sulphate deposition in porous rock was measured while flooding Berea core samples of uniform properties with supersaturated brine. The brine was formulated by mixing a Ca+2-rich solution with a SO4−2-rich solution at the core inlet. The rate of CaSO4 scale formation was estimated by monitoring the core effluent's Ca+2 ion concentration. Several parameters were varied including temperature, pressure, degree of brine super-saturation, and flooding velocity.
The results indicated increased rate of CaSO4 precipitation at higher temperatures, higher flood velocities, and greater brine super-saturation, whereas pressure had a slight effect on CaSO4 deposition. The results were utilized to build a general reaction rate equation to predict CaSO4 deposition in Berea sandstone for a given temperature, brine super-saturation, and flooding velocity.
Modeling the Effects of Compositional Changes in Transient Flow of Gas Condensate Reservoirs
Authors: Olaberinjo A. F. 
Published: December 2007

Abstract
Gas condensate reservoirs exhibit complexities due to the production of gas, condensates and many times, in situ oil phase. As the average reservoir pressure in a gas condensate reservoir continues to decline on production, condensate drop out occurs across the reservoir. Pressure decline between the reservoir boundaries and the well bore could lead to condensate formation near the well bore.
This paper considers the flow behavior in gas condensate reservoir and presents an approach for calculating the pressure depletion performance of a gas condensate reservoir from the original reservoir fluid composition using the vapor – liquid equilibrium calculations, the fluid properties, dimensionless properties, and retrograde liquid accumulation as guides.
The results correspond to drawdown analysis of a condensate reservoir where flow of the phase occurs. It is also a compositional analysis and includes the composition of the hydrocarbon fluid up to and including C7+. The presence of non-hydrocarbon impurities such as Carbon dioxide, Nitrogen and Hydrogen Sulphide are also considered. The comparison with other standard work on transient pressure analysis from gas condensate reservoirs showed that the approach is satisfactory.
A principal use of the method would be for the initial estimation of pressure depletion pattern after discovery of a gas condensate reservoir, where the compositional analysis of the reservoir fluid may be only approximate and the dew point if not known, is assumed to be the reservoir temperature and pressure. It is also a valuable tool during the production period for reservoir surveillance and monitoring.
Next Generation Expandable Completion Systems
Authors: Innes Gareth , Morgan Quentin , Macarthur Ally , Green Annabel 
Published: December 2007

Abstract
This paper documents an 18-month expandable technology research and development effort that has culminated in a system that enables a new approach to reservoir architecture.
The drive for maximum well productivity compels oil and gas companies to consider openhole completion strategies. However, historical uptake has been impeded by inability to achieve effective zonal isolation. The Expandable Reservoir Completion [ERC] combines slotted and solid expandable technology and features a return to conventional unexpanded premium connections to deliver a freely configurable reservoir completion architecture, offering a combination of openhole production performance and cased hole functionality.
Fundamental to the new Expandable Reservoir Completion is a unique, selective rotary compliant expansion technique, which is used to clad the formation wall with expandable screens, slotted liner or solid tubulars with sealing units. This technique facilitates unparalleled flexibility in reservoir design by allowing sections of conventional casing to remain unexpanded between zones. This enables integration with conventional flow control and intelligent completion equipment, ultimately permitting selective isolation & production control.
This paper outlines detailed test data generated by the development program, which included three downhole field trial installations. In addition to this, information from the first global commercial installations will be presented, from pre-job planning through to post installation performance review.
The Expandable Reservoir Completion builds upon existing expandable sand screen and solid expandable technologies to deliver a combination of productivity and functionality previously unavailable to the petroleum industry.
Integrating Advanced Well Completion Technology Improved Well Performance & Maximized Recovery_Case History
Authors: Sunbul A. H. , Al-Mohanna K. S. , Al-Qahtani H. B. , Hembling D. E. , Salerno G. 
Published: December 2007

Abstract
The combination of two new technologies - a production equalizer system combined with in-situ gas lift or electric submersible pumps (ESP) _ have been successfully implemented in Saudi Aramco offshore oil fields to optimize well rate and recovery. Merging these technologies has allowed Saudi Aramco optimal completion methods to exploit the remaining reserves from both Khafji and Safaniyah sandstone reservoirs.
This paper describes the benefits of integrating production equalizer technology with artificial lift (In- situ gas lift or ESP) to optimize production, delay water /gas coning, ensure uniform inflow, and prolong well life. A case history from Saudi Aramco will be presented, where these integrated technologies resulted in significant saving for the operator, and improved production performance in horizontal offshore oil wells.
Core Flood Study of Injectivity Decline by Mixing Produced Oily Water with Seawater in Arab-D Reservoir
Authors: Ba-Taweel Mohammed A. , Al-Anazi Hamoud A. , Al-Otaibi Msalli , Ballan Abdel N Abitrabi , Hilab Victor V. 
Published: December 2007

Abstract
A study was initiated to investigate impact of co-mingling produced water with seawater. The objective of the study was to assess injectivity decline in power water injectors caused by introducing produced water into the seawater injection system using core samples from Arab-D.
A series of core flood experiments was conducted to study formation damage aspects. The core flood study was done using water samples collected from shipping lines from Qurrayah to represent seawater and produced water from HRDH GOSP-2, due to lack of actual produced water from X field. The core flood experiments were performed to assess the effect of produced oily water on core permeability.
Experimental results showed that introducing different ratios of produced water (5, 10, 15 and 100 vol.%) to the seawater resulted in permeability loss of core samples. The damage was found to be proportional to the concentration of produced water. More reduction in permeability was found in low permeability core samples. However, lost permeability was restored by reversing flow in high permeability core (83 md).
Based on the obtained results, it is recommended to inject produced water into a dedicated disposal wells to avoid any injectivity decline in power water injectors and to maintain the injection rate target of 30 MBWPD. It is also recommended to maintain a good quality of the injected seawater. Low level of oil and solids in produced water should also be maintained.
General Transfer Function for Multiphase Flow
Authors: Lu H. 
Published: December 2007

AbstractWe propose a physically-motivated formulation for the matrix-fracture transfer function in dual permeability and dual porosity reservoir simulation. The current Barenblatt-Kazemi1–3 approach uses a Darcy-like flux from matrix to fracture, assuming a quasi steady-state between the two domains. However, this does not correctly represent the average transfer rate in a dynamic displacement. Based on one-dimensional analytical analyses in the literature we find expressions for the transfer rate accounting for both displacement and fluid expansion. The resultant transfer function is a sum of two terms: a saturation-dependent term representing displacement and a pressure-dependent term representing fluid expansion. The expression reduces to the Barenblatt form for single-phase flow at late times, but more accurately captures the pressure-dependence at early times. For displacement we consider both imbibition and gravity drainage processes.The transfer function is validated through comparison with one-dimensional fine-grid simulations and compared with predictions using the traditional Kazemi et al3 formulation. We show that our method captures the dynamics of expansion and displacement accurately, giving better predictions than current models, while being numerically more stable.
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

Abstract
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

ABSTRACT
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

ABSTRACT
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

ABSTRACT
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

Abstract
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

ABSTRACT
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

Abstract
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

Abstract
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.