bluuebunny/crossref_metadata_2025_split huggingface dataset:
Exciting New Technology for Monitoring HT Wells
Authors: Shanks David 
Published: July 2010

Abstract
It has historically been difficult to permanently monitor steam flood operations and also HPHT wells as the gauges available have short life spans and also give erroneous results. This project demonstrates a new, unique, robust, and available technology which will enable reliable monitoring of high temperature oil wells in the future. The ability to reliably monitor steam floods and HPHT wells will alter production and completion strategy and improve reservoir drainage.
This paper is outlining a new technology which allows us to monitor well pressure and temperatures up to 500 Celcius
The paper gives a description of a brief history of high temperature downhole gauges, a description of the development of the HT and XT technology and an outline of the first well installations.
This paper details the testing and results in the lab and also achieved results from the first field installations. Some test results are shown and early technology blockers discussed, as well as field installation problems and how they have been overcome. The paper has photographs of equipment and the installations, as well as graphical presented results.
We outline the state of maturity of this technology and the industry uptake. The results demonstrate a powerful new tool available to operators, previously thought unattainable.
In-situ Estimation of Relative Permeability from Resistivity Measurements
Authors: Li K. , Shapiro M. , Horne R. N. , Ma S. , Hajari A. , Mudhhi M. 
Published: July 2010

Abstract
Relative permeability is one of the key parameters governing fluid flow through porous media. Determination of relative permeability is traditionally conducted in the laboratory using either recombined reservoir oil or laboratory oil at simulated reservoir conditions or simply at laboratory room conditions. This is because it is expensive to sample representative uncontaminated reservoir fluids and extremely difficult to cut reservoir cores without altering their surface properties. Restoring rock properties to their original reservoir conditions has been a technical challenge to the industry. Upscaling laboratory special core analysis data to reservoir scale is also a concern. Consequently, the industry has been researching new methods to extract relative permeability in-situ including using specially designed permanent downhole electric resistivity array measurements.
In this study, a different approach was taken. A semianalytical model, developed to infer relative permeability from resistivity, was verified using experimental and field data. Relative permeability and resistivity were measured simultaneously in the laboratory. The results demonstrated that relative permeability derived from measured resistivity were close to the measured relative permeability. Relative permeability calculated from resistivity logs in two wells was compared to measured relative permeability with encouraging results. With this approach, it would be possible to obtain a distribution of relative permeability characteristics throughout an entire reservoir for enhanced reservoir engineering studies.
Investigating Productivity of Vertical and Horizontal Wells in One of the Persian Oil Fields
Authors: Mirzaei Paiaman Abouzar , Karimi Mohammad Rahim , Safian Gholam Abbas 
Published: July 2010

Abstract
First horizontal well in Iran was drilled in July 1992 in Marun oil field. Since then, most of the Persian giant oil fields have experienced horizontal drilling. This can be considered as a step towards improved recovery.
In this paper we try to compare the productivity of vertical and horizontal wells in a particular field. This field is located in the Southern part of Iran, with two separate carbonate reservoirs, R1 and R2. R1 is on the top and R2 in the bottom. An impermeable layer separates the two reservoirs. In this field about 50% of drilled wells are horizontal. Production results from horizontal wells are not satisfactory, and in most cases productivity index of horizontal wells is equal or even less than vertical wells, therefore the reasons should be investigated.
Control of Numerical Dispersion in Simulations of Augmented Waterflooding
Authors: AlSofi Abdulkareem M. , Blunt Martin J. 
Published: July 2010

Abstract
Augmented waterflooding is where a component is co-injected for the purpose of modifying the fractional flow curve: examples include polymer flooding, surfactant injection, low salinity waterflooding and carbonated water injection (including applications related to carbon dioxide storage). The numerical simulation of these processes is a challenge for several reasons: the appropriate physical behavior needs to be incorporated consistently into empirical models of the fractional flow, while the solutions should minimize numerical dispersion, allowing the correct and accurate tracking of compositional variations.
Traditional numerical simulations of these processes give excessive front smearing, requiring many thousands of grid blocks in one dimension to resolve the fronts adequately, rendering the predictions from three-dimensional simulations dubious at best. These erroneous predictions are not caused by phase dispersion (the improper prediction of water velocity), as in black-oil simulation, where the effect is less significant, but occurs because of the coupling of compositional dispersion with fractional flow. Small errors in composition alter the fractional flow, causing the development of incorrect wave speeds. The same effect is also seen in compositional simulation of gas injection.
We propose a simple method, based on the assumption of segregated flow within a grid block, that substantially reduces numerical dispersion. After comparing numerical and analytical results in one dimension, we implement the method into a three-dimensional streamline-based simulator of polymer flooding that also incorporates a physically-based model of the fluid rheology. We demonstrate that traditional simulation methods can vastly over-estimate recovery, potentially leading to poor injection design and management decisions. We demonstrate the utility of our approach by suggesting optimal strategies for the design of polymer injection based on our improved simulation technique. We also discuss extensions of the method to fully compositional displacements involving many chemical components.
Mechanistic Modeling of Chemical Transport in Naturally Fractured Oil Reservoirs
Authors: Abbasi-Asl Yousef , Pope Gary A. , Delshad Mojdeh 
Published: July 2010

Abstract
Surfactants both change the wettability and lower the interfacial tension by various degrees depending on the type of surfactant and how it interacts with the specific oil. Ultra low IFT means almost zero capillary pressure, which in turn indicates little oil should be produced from capillary imbibition when the surfactant reduces the IFT in naturally fractured oil reservoirs that are mixed-wet or oil-wet. The question is then what is the transport mechanism for the surfactant to get far into the matrix and how does it scale with distance in a matrix block of a fractured reservoir?. Recent dynamic laboratory data suggest that the process is faster when a pressure gradient is applied compared to static imbibition tests. A mechanistic chemical compositional simulator was used to study the effect of pressure gradient on chemical oil recovery from naturally fractured oil reservoirs for several different chemical processes (polymer, surfactant, surfactant-polymer, alkali-surfactant-polymer flooding). The fractures were simulated explicitly by using gridblocks with fracture properties. Both homogeneous and heterogeneous matrix blocks were simulated. Microemulsion phase behavior and related chemistry and physics were modeled in a manner similar to single porosity reservoirs. The simulations indicate that even very small pressure gradients (transverse to the flow in the fractures) are highly significant in terms of the chemical transport into the matrix and that increasing the injected fluid viscosity greatly improves the oil recovery. Large-scale simulations show that the transverse pressure gradients promote transport of the surfactant into the matrix at a feasible rate even when there is a high contrast between the permeability of the fractures and the matrix. These simulations indicate that injecting a chemical solution that is viscous (because of polymer or foam or microemulsion) and lowers the IFT as well as alters the wettability from mixed-wet to water-wet, produces more oil and produces it faster than static chemical processes. These findings have significant implications for enhanced oil recovery from naturally fractured oil reservoirs and how these processes should be optimized and scaled up from the laboratory to the field.
Coning Control and Recovery Improvement Using In-situ Water Drainage/Injection in Bottom - Water - Drive Reservoir
Authors: Jin L. , Wojtanowicz A. K. 
Published: July 2010

Abstract
Technology that directly controls water coning employs in-situ water drainage using oil wells with downhole water sink (DWS) bottom completions. With DWS, the well's oil productivity dramatically improves as oil can be recovered from a thin pay zone underlain by bottom water – an impossible undertaking for conventional wells. However, concurrent drainage of large volumes of water depresses water drive – particularly in the reservoir systems with small aquifers.
A natural extension of the water sink technology for small aquifers is the concept of returning the drained water to the same aquifer using triple-completed wells with downhole water loop (DWL). DWL technology retains all benefits of water coning control without depleting energy of water drive. However, DWL well completions have to be properly spaced to avoid pressure interference and the drained water must be oil-free to be injected in-situ into the same well.
The reported simulation study compares recovery performance of conventional, DWS and DWL wells in variety of oil reservoirs with bottom water coning from aquifers of different size and strength. The results show increasing superiority of DWL over conventional and DWS wells in reservoirs with decreasing aquifer strength. For example, when the aquifer is big, the DWL well recovery is similar to that for conventional and DWS wells but is 5-fold slower than that for DWS. However, when the aquifer is small, DWL recovers 60 percent more oil with 43 percent less water in 10 percent shorter time comparing to conventional well, while DWS fails to perform at all due to the fast depletion of reservoir pressure.
Also, the simulation experiments demonstrate operational flexibility of DWS and DWL wells. For conventional wells, a small improvement in recovery requires reduced production rate and extended producing time. In contrast, the recovery process of DWS and DWL wells can be optimized for maximum recovery, minimum production time or minimum produced water by seeking the best combination of the oil production and water drainage/injection rates.
Scale Dependence of Diffusion in Naturally Fractured Reservoirs for CO2 Injection
Authors: Alavian S. A. , Whitson C. H. 
Published: July 2010

Abstract
Based on detailed compositional simulations of matrix/fracture systems, we present results of the impact of diffusion on oil recovery by CO2 injection for small-scale laboratory experiments and field-scale systems. We consider reservoir conditions that lead to a range of recovery mechanisms from clearly immiscible to near-miscible.
Laboratory experimentation is a desirable approach to understanding the recovery mechanism of CO2 injection in fractured oil reservoirs because an unusual combination of complex physical phenomena exists. A fundamental problem with this approach is scaling the results to field conditions, and particularly matrix block size which is often many (5–100) times larger than laboratory cores. Molecular diffusion is clearly affected by matrix block dimensions, and any affect of diffusion on the recovery mechanism would also be scale dependent. In this paper we provide guidelines and computational examples of laboratory tests to study CO2 recovery processes, including diffusion. We also study the change in recovery processes as matrix/fracture dimensions approach field scale.
We recommend using reservoir core or outcrop samples similar to the actual reservoir rock, with dimensions (5–25 in2 horizontal area and 10–30 in high). A synthetic model oil can be constructed to mimic PVT properties of the actual reservoir oil, and in particular the minimum miscibility pressure (MMP) as defined by a traditional 1D multi-contact displacement process – MMP1D, reduced gas-oil interfacial tensions (IFT) and oil-gas density differences. The core should be placed in a container with annular space representing the fracture. CO2 is injected at various rates into the annular space, at relevant reservoir pressures both above and below the MMP1D.
In this work, the effect of several key parameters are studied – matrix permeability, matrix block size, CO2 injection rate and reservoir pressure. One of the key results is the effect of diffusion on oil recovery, and how it varies with matrix block size and CO2 injection rate. We show that diffusion has a dominant effect on recovery mechanism in experimental tests, except at very low CO2 injection rates. For field-scale matrix/fracture systems, diffusion has a significant effect on the rate of recovery, the effect becoming noticeable for low reservoir pressures and/or high fracture densities.
Compared with earlier studies on the Iranian Haft-Kel reservoir considered in this paper, our current work shows that the rate of high recoveries by CO2 injection reaches more than 90% 2–10 years with diffusion, versus &gt;100 years in the absence of diffusion, for an 8x8-foot matrix grid.
Comparison of Methods for Drainage Relative Permeability Estimation From Displacement Tests
Authors: Hussain F. , Cinar Y. , Bedrikovetsky P. 
Published: July 2010

Abstract
This paper compares classical and contemporary methods used to obtain relative permeability from dynamic experiments. We apply a variety of analytical, semi-analytical and history matching methods to analyze experimental data of oil-water unsteady-state drainage displacements. The analysis involves two types of error: bias and variance errors. The bias error in the resultant relative permeabilities mainly comes from the smoothening and differentiation of the experimental data while the variance error represents statistical uncertainty in measurements. We elect to use our own experimental data to minimize the variance error. We compare the numerical and functional fitting methods proposed for the differentiation and apply spline and Gaussian functions for fitting production and pressure data, respectively. We use spline fitting improved by time-domain data sampling to achieve a more effective history match. This approach minimizes the effects of non-uniqueness and shape dependency of relative permeability curves. We present a modification of the semi-analytical method of Civan and Donaldson (1989).
Comparison of different methods shows that analytical methods are in agreement with each other but differ from the semi-analytical and history matching methods. The modified semi-analytical approach agrees well with the improved history matching. The spline and Gaussian functions for fitting experimental data are capable to preserve the data shape and yield less bias error. The function fitting methods are more effective than numerical methods in differentiation/integration of experimental data, preserving the features of the data and minimizing the errors. Semi-analytical methods provide a better first guess for history matching. Use of the cubic spline curves for relative permeability makes the relative permeability curve more flexible and any shape of the curve can be produced. There is a trade-off between the simplicity of the conventional Corey-type power law function and the accuracy of the cubic splines.
Impact of Distillation on the Combustion Kinetics of High Pressure Air Injection (HPAI)
Authors: Barzin Y. , Moore R. G. , Mehta S. A. , Ursenbach M. G. , Tabasinejad F. 
Published: July 2010

Abstract
During the last two decades HPAI (High Pressure Air Injection) has proven to be a successful recovery method in deep light oil reservoirs. Distillation, flue gas drive and thermal front effects are the most dominant mechanisms associated with oil recovery in HPAI processes. This paper describes the results and observations of an experimental study conducted to characterize distillation, not only as a recovery mechanism but moreover as a phenomenon that impacts the kinetics of light oil combustion in HPAI.
Distillation or vaporization-condensation of light fractions of oil in thermal processes, more frequently in steam flooding and in-situ combustion, has been studied since its first recognition in 1960. Compositional effect of distillation on phase behavior of light oils, through stripping, and displacement of light ends through vaporization-condensation has been recognized as important. However, certain aspects of distillation such as the latent heat associated with vaporization of hydrocarbons, type of residual fuel remaining in the liquid phase after progression of an evaporation front, and more importantly the type of fuel transferred to the vapor phase through vaporization, all of which impact the kinetics of light oil combustion, has been missing in HPAI studies.
This study aims to shed light on the impact of distillation on formation and progression of the thermal front and reaction kinetics associated with the vapor phase oxidation/combustion. For the purpose of this study, oxygen and nitrogen injection experiments were performed on a recombined light oil core sample in a 45cm long, ramped temperature oxidation (RTO) reactor. This paper concentrates on selected tests which highlight the distillation behavior.
The presence of an endothermic vaporization front accompanying the exothermic thermal front in the RTO experiments was observed in this research. The nature of the thermal front depends on whether the concentration of hydrocarbon in the vapor phase falls in the flammable range.
MEOR From Lab to Field
Authors: Thrasher D. , Puckett D. A. , Davies A. , Beattie G. , Gordon Pospisil G. , Boccardo G. , Vance I. , Jackson S. 
Published: July 2010

Abstract
Progression of Microbial EOR (MEOR) technology from the laboratory towards field trial is described. An overview is provided of evaluation steps and field trial risk management through laboratory testing and numerical simulation, together with assessment of operational factors which could impact a long-duration field trial.
Previously MEOR has often been applied in onshore operations which carry relatively low risk. Where MEOR is to be applied in high value wells or higher risk environments such as the arctic or offshore deepwater, a higher degree of assurance is necessary to mitigate technical risks and maximise economic value. It is also essential to have sufficient understanding of base performance to ensure appropriate application and interpretation of the EOR process. To ensure success of an MEOR process, there needs to be a sufficient understanding of the performance of the microbes and the relevant MEOR mechanisms operating in the specific reservoirs.
Multiple processes have been characterised and represented to enable improved understanding of a microbial technology and its potential field implementation.
This paper will focus on screening of candidate reservoirs, and the methodology adopted to upscale core-scale results to prediction of performance in the field. This will include the choice of simulation models used for mechanistic understanding at the core scale and prediction of performance at the reservoir scale. It will also discuss some of the field operational aspects which need to be considered for well selection for field trial, including injectivity and surveillance requirements. Potential constraints on application of MEOR in the field have been identified, assessed and mitigated where possible in order to maximise chances of success.
MEOR technologies are often poorly understood, which creates uncertainty and apprehension around their use. The approach described here has been used to reduce uncertainty in progressing towards field application of a novel MEOR technology.
Effect of Wettability and Interfacial Tension on Microbial Improved Oil Recovery with Rhodococcus sp 094
Authors: Afrapoli M. Shabani , Alipour S. , Torsaeter O. 
Published: July 2010

Abstract
Results of coreflooding experiments with Rhodococcus sp. 094 species have already revealed that the bacterium is able to increase oil recoveries up to 9 %. Subsequent investigations have been carried out in order to recognize the complex mechanisms. Although published results proposed wettability changes in core plugs and favourable changes in the flow pattern as the active mechanisms but the potential of interfacial tension (IFT) and contact angle parameters was not fully understood in an aerobic process.
The present paper is a continuation of a series of laboratory experiments and consists of interfacial tension and contact angle measurements by an automated pendant drop goniometer. A refined hydrocarbon as the drop and two variants of bacteria suspended in brine as the continuous phase were employed. IFT and contact angle experiments were conducted in a static and a dynamic condition and quartz plates with two initial wettabilities were used. A certain volume of the bacterial solution and a short observation time is used in the static condition and the measurements show that by using bacteria, IFT is lowered from 18.3 mN/m (brine) to 13.6 mN/m (bacteria) and the contact angle changes slightly. However, our hypothesis is that the bacteria are capable of forming very stable emulsions of oil in brine and the real IFT value is much lower and the contact angle changes significantly. In the static condition, metabolic activities that lead to reduction of interfacial tension or contact angle changes are stopped due to the lack of nutrients and oxygen during the short observation period.
Therefore a constant flow of fresh bacterial suspension with enough nutrients and oxygen is ensured in the dynamic status. The IFT and the contact angle values obtained are presented in both conditions. The results show that the interfacial tension in the case of continuous flow of fresh bacteria is close to 5 mN/m. It is also observed that the contact angle is lower in the dynamic system compared to the static system. The new experimental procedure is more suitable for investigation of IFT reduction mechanisms in aerobic microbial improved oil recovery processes.