bluuebunny/crossref_metadata_2025_split huggingface dataset:
Asphaltenes Deposition Control in Lake Maracaibo Crude Oil Production
Authors: García María del Carmen , Chiaravallo Nicolás 
Published: December 2007

Abstract
Asphaltene deposition in oil production constitutes a critical and difficult to control problem, in terms of productivity and production operation costs, going from the reservoir to surface facilities. This phenomenon causes severe plugging and flow reduction due to phase changes in the crude oil through its production. When pressure declines in the reservoir, due to its exploitation, the single phase system may undergo asphaltenes precipitation and deposition, specially near the bubble point, where their solubility reaches a minimum. Severe formation damages occur when this pressure reduction takes place within the reservoir, and asphaltenes deposit in the porous media. The magnitude of the asphaltene precipitation tendency is strongly related with the crude oil characteristics, considering the asphaltene particles stabilization by other components of the oil. Prevention methods oriented to the asphaltenes deposition control include chemical additives injection. These products have the particularity of disperse or inhibit the asphaltenes aggregation, avoiding the formation of precipitates that eventually deposit on metal or mineral surfaces, causing a severe flow reduction. The main purpose of this work is to show an experimental methodology oriented to the selection of appropriated asphaltene inhibitors to be applied under surface, production and reservoir conditions. Dead oils characterization, along with several commercial additives effectiveness evaluation at surface conditions, followed by PVT studies on bottomhole crude oil samples, allowed to design adequate asphaltene prevention treatments for every particular case. Dead oil studies included SARA characterization and asphaltenes precipitation trends. Live oils analysis were performed by means of asphaltenes dispersion vs. pressure curves, asphaltenes flocculation onsets under isothermal pressure depletion, and a selected inhibitor evaluation. Examples from operations carried out in western Venezuelan facilities, illustrate the benefits derived from this methodology.
A Streamline Approach for Integrating Transient Pressure Data into High Resolution Reservoir Models
Authors: Kulkarni Kari Nordaas , Datta-Gupta Akhil , Vasco D. W. 
Published: December 2007

Abstract
Streamline models have shown significant potential in integrating dynamic data into high-resolution reservoir models in a computationally efficient manner. However, previous efforts towards production data integration using streamline models have been limited to tracer data and multiphase production history such as water-cut at the wells. In this paper we generalize the streamline approach to transient pressure applications by introducing a ‘diffusive’ time of flight along streamlines. We show that the ‘diffusive’ time of flight allows us to define drainage areas or volumes associated with primary recovery and compressible flow under the most general conditions. We then utilize developments in seismic tomography and waveform imaging to formulate an efficient approach to integrating transient pressure data into high-resolution reservoir models.
Our proposed approach exploits an analogy between a propagating wave and a propagating ‘pressure front’. In particular, we adopt a high frequency asymptotic solution to the transient pressure equation to compute travel times associated with a propagating ‘pressure front’. The asymptotic approach has been widely used in modeling wave propagation phenomena. A key advantage of the asymptotic approach is that parameter sensitivities required for solving inverse problems related to production data integration can be obtained analytically using a single streamline simulation. Thus, the approach can be orders of magnitude faster than current techniques that can require multiple flow simulations.
We have applied our proposed approach to both synthetic and field examples. The synthetic example utilizes transient pressure response from an interference test in a nine-spot pattern. The spatial distribution of permeability is estimated by matching arrival times of the ‘pressure front’ in each of the observation wells. The field example is from the Conoco Borehole Test Facility in Kay County, Oklahoma. A series of pressure interference tests were performed in a skewed five-spot pattern to identify the distribution and orientation of the natural fracture system at the Fort Riley formation. We have inverted the pressure drawdowns at the observation wells to create a conceptual model for the Fort Riley formation. The predominant fracture patterns emerging from the inversion are shown to be consistent with outcrop mapping and crosswell seismic imaging.
Sequential Neural Simulation: A New Approach for Stochastic Reservoir Modelling
Authors: Niu Y. , Wong P. M. , Chen L. 
Published: December 2007

AbstractThis paper proposes a new and practical neural network for stochastic reservoir modelling. The new approach known as sequential neural simulation (SNS) is developed based on the use of an ensemble of supervised neural networks within the conventional sequential simulation framework. Compared to the sequential Gaussian simulation (SGS), SNS uses a data-driven conditional distribution and can handle multivariate inputs and non-linearity. It does not require any (cross) variogram models and does not use a parametric function for simulation. The formulation of the algorithm however does not guarantee the reproduction of the desired statistics. The methodology is demonstrated in a fluvial-deltaic reservoir in China. Porosity is simulated using different number of inputs followed by oil in place estimation. The study shows the simplicity of the methodology for the incorporation of multiple soft information.
Optimising Performance of Mature Reservoir: An Innovative Use of Coiled Tubing Drilling Technology to Tap Unswept Reserves, Alwyn North UKCS
Authors: Lheure S , Müller S , Kimber R. , Holehouse S. G. 
Published: December 2007

Abstract
This paper describes the rationale, the planning and the preliminary results of the first Coiled Tubing Drilling (CTD) experience for TotalFina. The objective was to enhance production from a high water-cut oil well producing under unstable conditions and located in an area of possible upsides. This well was drilled in 1990 on the edge of a fault-scarp degradation complex in the Brent East panel of the Alwyn Field. The geological uncertainties in this complex area needed to be reduced and it was necessary to reassess seismic, core and reservoir data to progress the current knowledge base. Analytical calculations supported 3D reservoir modelling techniques to constrain some of the uncertainties.
Drilled in 1999, well 3/9a-N30Y was the first coiled tubing sidetrack from a producing well on Alwyn. The motherbore, 3/9a-N30, was still producing around 380 stb/d, although production had recently become intermittent.
The well path presented a challenging trajectory due to the location of the unswept area in relation to the direction of the motherbore. After drilling 240m a series of operational issues arose, necessitating the drilling of the world's deepest open hole sidetrack with coiled tubing, but ultimately the BHA was left in hole. The coiled tubing was then utilised as an uncemented liner, perforations using slim guns were added along the liner, and the well was brought onto production. The CTD drain alone produced at an initial rate of 2900 stb/d, which stabilised out at 1200 stb/d after an initial rise in water cut.
The successful outcome of 3/9a-N30, which was drilled in a complex offshore environment, confirmed the viability of CTD as a technique for accessing smaller pockets of remaining oil, whilst some of the operational difficulties encountered highlighted the need to simplify future trajectories to maximize the chance of success. With the possibility of drilling future CTD wells, further increases in productivity and reserves will be achieved at a significantly lower cost compared to conventional drilling.
Advanced Sensor Infrastructure for Real Time Reservoir Monitoring
Authors: Kluth E. L. E. , Varnham M. P. , Clowes J. R. , Kutlik R. L. , Crawley C. M. , Heming R. F. 
Published: December 2007

Abstract
Over the past ten years Chevron and SensorDynamics have partnered in developing a practical approach to intensive surveillance of remote downhole oil and gas wells and related production infrastructure.
The work has resulted in a unique family of slim-line fiber optic sensors, along with a simple method of deploying these sensors remotely in oil and gas wells, using conventional hydraulic control lines as pathways into the heart of the reservoir. Most importantly the program has also produced coating technology that stabilizes the fiber optic sensors and cables in the high-temperature, high-pressure environments of deep wells.
Sensors cover a wide range of parameters, including distributed temperature, pressure, acoustic sensors and acoustic sensor arrays for in-reservoir imaging of formation, fluid front movements and seismic relaxation.
The result of this long-term partnership has been an integrated solution that forms a credible basis for permanent and intensive surveillance of oil and gas reservoirs, a solution that ensures availability of dynamic downhole data over the life of a reservoir. It has the additional advantage of allowing sensor up-grade, sensor replacement and the addition of new sensor types as these become available – without interruption of normal production and at minimal incremental cost.
We report on a system that can address EOR applications, intelligent well monitoring and that we believe offers a basis for instrumenting deep and hot sub-sea reservoirs and sub-sea production infrastructure.
We report some of the key issues in deploying sensors in hydraulic control lines in oil wells, in protecting sensors in harsh downhole environments (250deg C, 600 bar) and sensor performance results, from laboratory and field test work. We also offer some views on the implications to the future of real-time integrated reservoir management, where availability of downhole information has important value in all phases of the life of a field – from cradle to grave.
Interfacial Instabilities In Porous Media
Authors: Castor T.P. , Somerton W.H. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
Spontaneous emulsification at liquid-liquid interfaces and Haines' jump phenomenon at liquid-gas interfaces may be explained in terms of classical fluid mechanics, mass and energy diffusion and surface thermodynamics. These phenomena are examined in this paper in terns of an interaction between Marangoni effects and capillary forces. Marangoni effects refer to the motion of an interface due to gradients in interfacial tension.
The porous medium used to study these effects is described geometrically as an interconnected network of converging-diverging channels. The flow of two immiscible fluids in these channels is described by the Navier-Stokes equations at very low Reynolds numbers. Differences in the potential (temperature and/or concentration) of potential (temperature and/or concentration) of these fluid phases will induce mechanical movement of the interface.
The resultant unsteady motion is modelled as a classical Rayleigh flow or suddenly accelerated plane flow. This motion will initiate disruption plane flow. This motion will initiate disruption of the interface if the pressure drop due to shear forces is greater than the pressure drop due to normal forces.
Analytical expressions developed in this work suggest parametric dependence of interfacial unstabilities in porous media on (i) differences in the kinematic and absolute viscosity (ii) the magnitude and direction of the interfacial tension gradient due to temperature and/or concentration differences (iii) absolute magnitude of the interfacial tension (iv) wettability of the porous matrix and (v) a geometric factor which is porous matrix and (v) a geometric factor which is characteristic of the microscopic structure of the porous medium. The influence of these parameters is supported by experimental data from the parameters is supported by experimental data from the literature.

Introduction
Additional chemical and/or thermal energy is required to overcome the capillary forces which entrap large quantities of residual oil in depleted petroleum reservoirs. Removal or reduction of interfacial forces with or without the reduction of viscous forces will allow the mobilization of isolated droplets and ganglias of oil and the subsequent formation of local regions of high oil saturation. The reservoir mechanics of tertiary floods will thus have to consider a microscopic mobilization efficiency in addition to the macroscopic displacement and areal sweep efficiencies. Physical and mathematical conceptions of the isolation and mobilization mechanisms will be necessary for the quantifying of microscopic efficiencies.
Improved Oil Recovery Based On Optimal Waterflood Pressure
Authors: Kolbikov S. V. , Vaughn H. F. , Usmanov A. A. , Chalov S. E. 
Published: December 2007

Abstract
The paper reviews oil recovery improvement for black oil fields with low bubble point pressure, which are developed under waterflood. The Kogalym field, located in Western Siberia, is approximately 2,400 meters true vertical depth, and produces from Cretaceous and Jurassic sand deposits. The black oil system has a bubble point pressure of 8.5 Mpa, less than 35 % of the initial reservoir pressure of 123.7 MPa. The optimal development strategy of such reservoir depends on selecting water flood elements, well pattern and flood pressure. The focus of this work is to justify an optimal waterflood pressure. In 1997-98 numerical simulation was performed on a separate waterflood pattern. A representative geological model of the pattern was constructed on the basis of comprehensive core analysis data from the well # 1037. Several development strategies were tested on the ECLIPSE model for various waterflood pressures: 24, 19 and 15 MPa. The maximum oil recovery factor (ORF) was obtained with a waterflood pressure of 15 MPa. The most economic case was with a waterflood pressure of 19 MPa. This pressure of 19 MPa is the optimal value of waterflood pressure, which is 75% of the initial reservoir pressure and exceeds the bubble point by more than 10 MPa. The analysis of the Kogalym field development for the last four years confirms these conclusions.
Generation of Fractal Porosity and Permeability Fields Conditioned to Well-Test Pressure and Geostatistical Data
Authors: Zeybek Ayse Donmez , Onur Mustafa 
Published: December 2007

Abstract
In recent years, it is shown that the inverse problem theory based on Bayesian estimation provides a powerful methodology not only to generate rock property fields conditioned to both static and dynamic data, but also to assess the uncertainty in performance predictions. To date, standard applications of inverse problem theory given in the literature assume that rock property fields obey multinormal distribution and are second order stationary. In this work, we extend the inverse problem theory to cases where rock property fields (only porosity and permeability fields are considered) can be characterized by fractal distributions. Fractional Gaussian noise (fGn) and fractional Brownian motion (fBm) are considered. To the authors' knowledge, there exists no study in the literature considering generation of fractal rock property fields conditioned to dynamic data; particularly to well-test pressure data.
We show that available Bayesian estimation techniques based on the assumption of normal/second-order stationary distributions can be directly used to generate conditional fGn rock property fields to both hard and pressure data because fGn distributions are normal/second-order stationary. On the other hand, we show that because fBm is not second-order stationary, these Bayesian estimation techniques can only be used with implementation of a pseudo-covariance (generalized covariance) approach to generate conditional fBm fields to static and well-test pressure data.
Using synthetic examples generated from two and three-dimensional single-phase flow simulators, we show that the inverse problem methodology can be applied to generate realizations of conditional fBm/fGn porosity and permeability fields to well-test pressure data. We conclude by showing how one can then assess the uncertainty in reservoir performance predictions appropriately using these realizations.
A Successful In-Situ Combustion Pilot In The Midway-Sunset Field, California
Authors: Counihan Thomas M. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
This paper presents a case history of a technically and economically successful dry in-situ combustion pilot conducted in a thick, moderately dipping, heavy oil reservoir located in the Mid-way-Sunset Field in western Kern County, California. The pilot was situated near the oil-water contact with a heterogeneously depleted area updip in the regionally extensive, homoclinal Potte Sand of Upper Miocene Age. With less than 15% of the original oil-in-place produced, reservoir and production analyses indicated the impending production analyses indicated the impending demise of economic cyclic steaming. This trend coupled with poor results from laboratory steam drive tests and minor water encroachment problems in the field led to the consideration of in-situ combustion as the most reasonable mechanism for recovery of the remaining oil reserves. Air injection into the arbitrarily delineated central Potter zone began in January 1972. Production Potter zone began in January 1972. Production analysis and an extensive coring program following 3-1/2 years of operation indicated nearly 80% of the original oil-in-place had been recovered from the initial pilot pattern. Two additional patterns were fired, one of which was a former patterns were fired, one of which was a former steam drive pilot which gives a basis for comparison of the two enhanced recovery methods in this reservoir.

Introduction
All three areally non-contiguous, inverted five-spot in-situ combustion patterns were located in the Potter Sand of the S-1/2, NW-1/4, Section 23, T31S, R22E (see Figure 1).
Development of the Potter Sand in this area of Section 23 began in 1910 by Chanslor-Western Oil and Development Company's predecessor, Chanslor-Canfield Midway Oil Company. By the advent of the cyclic steam (huff and puff) recovery method in this section in 1965, primary production had recovered less than 2% of the original oil-in-place. Cyclic steam stimulation recovered an additional 12% of the original oil-in-place by the time Well 154 began air injection in January 1972.
The Potter Sand of the portion of Section 23 discussed in this paper yields less ultimate oil recovery by the cyclic steam method than areas to the west (e.g. Section 22, T31S, R22E) with equivalent well spacing. Evidence of this can be seen in the increased rate of decline: 10–20% per year for "Section 23" versus less than 10% per year for Section 22.
Log Analysis In The Shallow Oil Sands Of The San Joaquin Valley, California
Authors: Vohs J.B. 
Published: December 2007

Abstract
Many fields in the San Joaquin -Valley of California produce oil from a depth of 2,500 ft or less. During the period of primary production in these fields, evaluation of potential pay intervals from logs was restricted to explanation of ES logs and correlation. With the introduction of secondary and tertiary recovery techniques the need for more and better answers, more quickly available, became apparent. However, several log-analysis problems had to be resolved. Formation evaluation using well logs was complicated by the shaliness of the sand intervals, the low and variable salinity of the formation waters, and the presence of low-pressure-gas (depleted) zones in many of the shallow sands.
Solutions to these problems have required more modern logging programs art interpretation techniques. Logs available for the evaluation programs art interpretation techniques. Logs available for the evaluation of these sands are the Dual Induction-Laterolog (DIL*), the Compensated Formation Density log (FDC*), the Compensated Neutron log (CNL*), and the Microlaterolog* or Proximity* log. With this suite of logs it is possible to determine the shale content, porosity, saturation in the possible to determine the shale content, porosity, saturation in the flushed zone, and water saturation of the sand, and to locate the low-pressure-gas sands and depleted zones. In cases where fresh water and oil are interlayered it is possible to tell which sands contain oil and which contain only water. Because a quick interpretation is required, wellsite techniques are called for. These will be described. More sophisticated computer techniques are, of course, available. These will not be covered in this paper.

Introduction
Oil has been produced since early in the century in the San Joaquin Valley of California, indicated as the circled area on the map of Fig. 1.
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Wellsite Formation Analysis Using The Ddl Computer
Authors: Head Mickey P. , Gearhart Marvin 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.

Abstract
The Direct Digital Logging System, first introduced in 1975 as a new concept in well logging, has proven the feasibility of digital systems for recording logs. The surface equipment necessary to produce logs includes a mini-computer and laser recorder, along with other input/output devices and is well sected for wellsite formation analysis. Log signals are sampled four times per foot and are recorded in engineering units on per foot and are recorded in engineering units on magnetic tape cartridges.
Depth shifting required to match subsequent logs to the base log is performed through a calculator type keyboard, with the data interpolated between the depth shift points. Interpolation is possible because of the three inch depth increments. The advantage of interpolation in depth shifting is that no data is lost or created at the depth shift points.
Environmental corrections are applied to the log trace data to remove borehole effects. Computer performed corrections such as borehole correction to the performed corrections such as borehole correction to the Induction Log and mud cake correction to the Sidewall Neutron Porosity Log removes the need for departure charts and hand calculations.
With the digital system, wellsite quick look calculations are performed after the logs are recorded and environmentally corrected, all the data is studied, appropriate parameters are selected, and the program is executed. The digital system is an improvement over existing analog systems because the digital system does not require parameter selection before the logs are run, and the computing is not performed as the well is logged. Digital quick look techniques presently available are logarithmic F overlays and R with porosity.
More detailed evaluation can be performed at wellsite, going beyond the quick look methods. For example, the Induction Electrical Log (IEL) and the Compensated Density Log (CDL) can be combined and solve for volume of shale, shale corrected porosity, and water saturation. Also the Sidewall Neutron Porosity Log (SNP) and the Compensated Density Log (CDL) combination will resolve cross-plot porosity and apparent matrix density, which combined with resistivity often provide good results in complex lithology. provide good results in complex lithology. The new concept of wellsite Direct Digital Logging and computed formation analysis opens a new era in log evaluation. The opportunity to obtain computed logs has been moved to the wellsite, and the applications are just being realized.