bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Effective Time-Splitting Technique for Full-Tensor Flow Model
Authors: Sutopo Sutopo , Arihara Norio , Yazawa Nintoku 
Published: December 2007

Abstract
A flux-continuous model incorporating full-tensor permeability has been developed for two-phase flow of immiscible and incompressible fluids. Full-tensor permeability is often required to characterize flow from the upscaling process in fine grids heterogeneous reservoirs.
The governing equations can effectively be formulated in fractional flow equations; i.e. in terms of global pressure and saturation equations. An algorithm is implemented applying a highly accurate numerical approach based on the mixed finite volume element (MFVE) method for discretizing the pressure equation, and a combination of the MFVE and the finite volume element (FVE) methods for the saturation equation. The saturation equation is discretized by means of a time-splitting algorithm that allows an explicit time stepping for FVE applied to the advection equation, and an implicit time stepping for MFVE applied to the corrective equation of capillary diffusion.
Numerical experiments of 1-D and 2-D flow are presented to demonstrate the efficiency and robustness of the time-splitting technique. The 1-D Buckley-Leverett displacements verify accuracy and numerical behavior of the proposed scheme. It is also used to determine the optimum time-stepping strategy. The 2-D simulation also show accurate results for full-tensor models and a highly heterogeneous reservoir. It is proved that proposed method can significantly reduce computational time for both 1-D and 2-D displacements.
Effect of Permeability Distribution and Interfacial Tension on Gas Condensate Relative Permeability: An Experimental Study
Authors: Jan Badrul M. , Siagian Ucok W. , Lee Robert L. 
Published: December 2007

Abstract
One of the unique characteristics of gas condensate fluid is the rate dependent relative permeability, also referred to as rate sensitive phenomenon. It has been reported that generated relative permeabilities from gas condensate fluid are sensitive to the flow velocity applied during the experiments. Different flow rate results in different relative permeability. However, this behavior is usually not observed with conventional oil-water or gas-water reservoir fluids and there is no clear answer for the observed rate sensitive phenomenon. This paper will address two of the possible factors that may have caused the dependency of relative permeability on flow rates, namely interfacial tension and permeability distribution. To achieve the mentioned objectives, we measured a series of two-phase relative permeability curves from near critical fluid by means of steady-state technique. A high pressure and high temperature (HPHT) coreflood rig was designed specifically for the purpose of this work. We measured relative permeability at various interfacial tensions and flow velocity. To look at the effect of permeability distribution, we conducted the same steady-state flow tests as in long core, but this time we cut the core to 5.0 in. in length. Results from the study indicate that relative permeability curves seems to straighten out whenever the interfacial tension of the system decreases and flow velocity increases. Experimental results from the short core show significant reduction of the rate sensitive phenomenon in gas and condensate relative permeability. We concluded that the relative permeability of gas condensate is a strong function of interfacial tension. We also found that permeability distribution has significant effect on rate sensitive gas condensate relative permeability. A higher degree of permeability distribution heterogeneity results in larger rate sensitive effect.
4D Seismic in Mapping the Change in Fluid Phase in Carbonate: A Case Study
Authors: Mitra Partha P. , Singh Kharak 
Published: December 2007

Abstract
The ability of 4D seismic to image the fluid flow and locate bypassed oil in between wells especially in carbonate is a real challenge. The seismic observables that change with time as the extraction of hydrocarbon continues may not always be mappable since normally Gassman's equation does not predict the nature of velocity sensitivity to fluid change in most carbonates. However the effect of change in reservoir parameters due to production has a direct impact on seismic signals and is preserved in the form of seismic signature in data volume if they are conditioned and equalized.
The paper presents a 4D study, which was carried out using two 3D seismic surveys acquired over one of the western offshore fields of India. The field produces from Eocene carbonate, which is affected by Karstifiaction. The base survey was carried out in 1989, before the commencement of production. The repeat survey was conducted in 1999, after a time lapse of ten years. The reservoir was developed with peripheral water injection and by 1999 had produced about 16% of initial oil in place. The hydrocarbon column is maximum in the southern part of the field and maximum production had taken place from this sector. The two survey geometries were different and basic processing of two vintages was carried out by two different vendors but more or less same processing sequences were followed. The conditioning and equalization of the datasets were done at post stack stage.
To ensure the repeatability test, non reservoir on both vintages was mapped, surface attribute was computed and difference map was generated. On the other hand, volumetric seismic attribute was computed between reservoir top and initial OWC for base and repeat survey. Difference volume was generated to map the areas affected by water influx and possible areas of bypassed oil. This was later supported by the simulation study.
Disposal of Mercury Sulfide and Residual Ash by Deep Well Injection
Authors: Brkic Vladislav , Omrcen Ivo , Omrcen Bozidar 
Published: December 2007

Abstract
INA Oil Company, Plc. Zagreb is a Croatian company engaged in the exploration and production of oil and gas, refining and distribution of petroleum products. An enormous quantity of hazardous waste is generated in oil and gas production and thus has to be disposed in a permanent and safe manner. In recent years, INA has been disposing waste by injection into exploration dry wells and production depleted wells.
A specific waste disposal problem has arisen in the process of gas and condensates in Molve, Kalinovac, Stari Gradec and Gola fields. Namely, mercury-sulfide, sulfur slurry and heavy metals have been separated during the production of gas and condensate.
Mercury-sulfide has been separated in the process of active coal utilization. The disposal of active coal saturated with mercury-sulfide is a very complex issue. So far, the methods of mercury-sulfide disposal have not been ecologically acceptable. However, on the basis of new experience and knowledge in that field, waste dispersed in a bentonite suspension may be disposed in a permanent and safe manner into appropriate geological formations. In the same way, when combusting various types of industrial and municipal waste, the problem of residual ash disposal emerges. Such residual ash contains heavy metals which may be permanently disposed by using the above mentioned method. This paper deals with the experience of waste disposal by deep well injection in the Republic of Croatia.
Rig Waste Reduction Pilot Project
Authors: Satterlee K. , van Oort E. , Whitlatch B. 
Published: December 2007

Abstract
Shell Exploration and Production Company (SEPCo) initiated the Rig Waste Reduction Pilot Project in 2001 to further its goals toward Sustainable Development. SEPCo ran the pilot project on two contract drilling rigs and a drilling and production platform. After characterizing and measuring the waste streams, 26 potential waste reduction strategies were considered for implementation. A preferential hierarchy for consideration was used: reduce, reuse, recycle, recover, and dispose. SEPCo found that its drilling discharges and non-hazardous oilfield waste (NOW) comprised the lion's share of the total waste and therefore represented the greatest opportunity for reduction. SEPCo used a combination of solids control efficiency, cuttings dryer technology, and new bulk mixing technology to reduce mud use by up to 20% and mud component packaging by up to 90%. Solid waste (consumables and trash) also comprised a large volume of waste. SEPCo implemented a sorting, compaction, and recycling process for this waste stream to reduce landfill disposal. This paper describes the process used by SEPCo to develop the pilot project, the strategies implemented, and the effectiveness of those strategies.
Options for the Recycling of Drill Cuttings
Authors: Page Paul W. , Greaves Chris , Lawson Rosey , Hayes Sean , Boyle Fergus 
Published: December 2007

Abstract
It is estimated that the UKCS produces between 50,000 to 80,000 tonnes wet weight of oily drill cuttings annually. With the implementation of OSPAR Decision 92, and given current offshore technology, it is no longer possible to discharge cleaned oily cuttings to sea. Increasingly stringent legislation also makes it likely that cuttings derived using water-based muds will not be discharged to sea in the future.
Although several commercially available treatment processes can remove oil from oil based mud (OBM) cuttings, there are few satisfactory outlets for the residual solid material most of which currently goes to landfill. In light of the legislative changes, increased focus on duty of care, and commercial considerations, viable alternatives are being sought for the recycling and reuse of large volumes of material from future drilling programs.
This paper examines possible options for converting drill cuttings into reusable secondary products and discusses the advantages and disadvantages of each option when considered against the criteria of environmental impact, technical risk, logistics, liability and cost. Examples of the research and pilot trials currently being undertaken to assess the feasibility of these options is discussed, as well as work being carried out to establish the variation in chemical composition of cuttings in the UKCS, since tolerance to the variation in the chemical characteristics of drill cuttings is a major issue for most of the end uses.
A Biodegradable Chelating Agent is Developed for Stimulation of Oil and Gas Formations
Authors: Frenier W. W. , Rainey M. , Wilson D. , Crump D. , Jones L. 
Published: December 2007

Abstract
Chelating agents are materials that are used to control undesirable reactions of metal ions. In oilfield chemical treatments, chelating agents are frequently added to stimulation acids to prevent precipitation of solids as the acid spends on the formation being treated. These precipitates include iron hydroxide and iron sulfide. In addition, chelating agents are used as components in many scale removal/prevention formulations. This current study is related to development of improved and biodegradable polyaminocaboxylic acid chelating agent formulations.
Chelating formulations based on ethylenediaminetetraacetic acid (EDTA) have been used extensively to control iron precipitation and to remove scale. Formulations based on nitrilotriacetic acid (NTA) and diethylenetriaminepentaacetic acid (DTPA) also are in use. Each of these materials has problems: 1) EDTA and DTPA have low solubility in hydrochloric acid and are not biodegradable. 2) NTA is acid soluble and biodegradable, but has a lower stability constant for iron than EDTA (or DTPA) and may be classified as an animal carcinogen. This paper describes the development and field-testing of formulations containing hydroxyethyliminodiacetate (HEIDA) salts for use in oilfield stimulation fluids.
Sodium HEIDA can be used in all of the formulations requiring EDTA-type chelating agents, including those for iron control during acidizing, scale removal treatments, and well cleanout operations. HEIDA biodegrades much more easily than EDTA or DTPA and has a much smaller environmental footprint (biodegradation, less material and less toxic corrosion inhibitors) than these chemicals. HEIDA is more soluble in HCl than EDTA, and therefore can control more Fe3+ than EDTA. The new formulation can be used to dissolve calcite and gypsum scale. It also can be used in acidic or alkaline well cleanout formulations with surfactants and mutual solvents. Field trials have shown that HEIDA formulations can be 1:1 substitutes for EDTA in oil and gas well treatments.
Vapor Recovery of Natural Gas Using Non-Mechanical Technology
Authors: Goodyear Mark A. , Graham Alexandra L. , Stoner John B. , Boyer Brian E. , Zeringue Lyle P. 
Published: December 2007

Abstract
There are approximately 250,000 tank batteries in the United States1. These tanks store crude oil and condensate prior to transportation to sales via pipeline, barge or trucking. The sources of the vent gases from tanks are from flash, standing and working losses. There are approximately 8,000 to 10,000 mechanical vapor recovery units (VRUs) installed at oil production sites with four tanks typically connected to each VRU2. Most of these tanks are fixed-roof storage tanks.
This project demonstrated the use of an alternative method for handling low-pressure natural gas that is typically vented to the atmosphere, flared or recovered with a mechanical compressor by oil and gas production facilities. This application used a venturi jet ejector as a device to compress natural gas from crude oil/water storage tanks to an intermediate pressure for use at the location or ultimate injection into the sales pipeline.
Upon injection of the oil into the storage tanks, lower molecular weight hydrocarbons dissolved in the crude oil come out of solution or "flashes" when the pressure drops as the oil enters the tank. The storage tanks are typically downstream of a low-pressure vessel such as a two or three phase separator or heater treater. The hydrocarbons that flash include methane, ethane, volatile organic compounds and hazardous air pollutants. These gases collect in the plenum of the fixed roof storage tanks that are typically used in oil and gas production operations.
Effect of Well Deviation on Slurry Friction Pressures
Authors: Pandey Vibhas J. , Goel Naval 
Published: December 2007

Abstract
Increase in friction pressure with the onset of proppant stages in a hydraulic fracturing treatment is a known phenomenon. With the introduction of proppant, the hydrostatic pressure due to the column of proppant-laden slurry increases and causes a reduction in surface pressure. However, it has been consistently observed that the apparent decrease of the surface pressure is less than the value calculated on the basis of increase in hydrostatic pressure alone, indicating that the excess is due to the additional friction imparted by the solids in the slurry.
When hydraulic fracturing treatments are carried out in deviated wells, the contribution of hydrostatic pressure to overall reduction of surface pressure may not be very significant, depending on the well deviation. The effect of well deviation on slurry friction is rarely reported in literature. As a result, a few correlations are available to predict slurry friction losses in deviated wells. To study the effect of inclination on proppant-laden slurry, bottom hole pressure (BHP) data are needed. Therefore, in the present study over 400 hydraulic fracturing treatments were selected, and around 100 of those with BHP data were analyzed. Results from the analyses indicated that the friction pressure observed in the slurry stages of deviated wells were significantly higher than those in vertical wells. Based on the observations, a new correlation is developed to incorporate the contribution of well deviation on slurry friction. Variables in the correlation include: proppant concentration, flow rate, tubular diameter and angle of deviation.
The developed correlation was then used to predict proppant friction in other wells, which were not considered in the study. The correlation predictions were also compared with other correlations currently used in the industry. The comparison shows a better prediction from the developed correlation. The correlation is easy to use and is being incorporated into the fracturing treatment simulator for field usage.
Coal Bed Methane Production
Authors: Simpson David A. , Lea James F. , Cox J. C. 
Published: December 2007

Abstract
Provided that certain conditions are met, Coalbed Methane (CBM) wells have demonstrated the capacity to continue to produce a significant proportion of their peak production rates at very low reservoir pressures. Low reservoir producing pressures require low bottom-hole and surface pressures. Chief among the conditions for high production rates is being able to manage water at low surface pressure. Minimum-net-positive-suction-head considerations limit artificial lift options. The dew point at low pressures allows large volumes of water to move as vapor—rendering mechanical separation equipment ineffective and leaving solids behind at inconvenient places. Temperature changes in buried piping condense water vapor and create both corrosion and pipe-efficiency problems. Low separator pressures preclude easy methods to remove liquid water. This paper addresses the design considerations for these low-pressure operations and related artificial lift systems
Effect of Non-Uniform Skin on Finite Conductivity Horizontal Well
Authors: Toufik Belhouchet , Tiab Djebbar , Jokhio Sarfraz 
Published: December 2007

AbstractThis paper investigates the performance of horizontal wells under the combined influence of wellbore friction, wellbore storage, and formation damage. A new model is proposed wihich couples wellbore, reservoir, and non-uniform skin, and takes into account the change in flow regime from laminar to turbulent along the wellbore.In the conventional perspectives, wellbore damage may be viewed as an additional pressure drop, is correct only for infinite-conductivity wellbore with uniform damage. It is shown in this paper that the wellbore damage may not be viewed merely as an additive pressure drop due to skin in the presence of friction inside the long horizontal section of the well. Wellbore hydraulics change the flux distribution (inflow profile) along the wellbore and, thus, result in additional pressure drop in the reservoir and across the skin zone. Horizontal wells, for a number of reasons, are unlikely to have smooth distributions of damage along their trajectories. Thus, segmented well testing would be ideal tool to estimate the skin, Si, of each segment especially in the zone where more severe damage is expected, because it delivers a detailed picture of the skin distribution along an extended horizontal well.Finite conductivity solution approaches to infinite conductivity solution at high conductivity values and high wellbore radius. The appearance of bi-linear, linear, and radial flow regimes depends upon the length of the well; for long wells, linear and bi-linear flow regimes are observed, and they are masked in the case of short wells. The perforation number effect appears only in the damaged case, when the open-hole scenario deviates from the two other cases. Another important factor, that affects the behavior of the pressure, is the dimensions of altered permeability region; the higher the radius of filtrate penetration, the higher the volume of affected region and therefore, the higher the loss in pressure. The effect of k/ks is more severe in small wells. Another correlation which allows determine kx directly from the intersection point with the half slope is presented using a new method of interference test interpretation of different segments with each other in the same well. Isolated segment testing would lead to the estimate the local skin factor, a possible indication of uneven damage distribution and a necessary variable for the optimization of matrix stimulation. Thus designing of a remedial treatment, both the type and the location of permeability damage must be considered.Several examples are included to illustrate the use of the model developed.
Effective and Ineffective Strategies for Mud Removal and Cement Slurry Design
Authors: Frigaard I. A. , Pelipenko S. 
Published: December 2007

Abstract
Uncontrolled flows of reservoir fluids behind the casing are relatively common. In worst cases these can lead to blow out, leakage at surface, destruction of subsurface ecology and potential freshwater contamination. Often, safe abandonment of such wells is not possible. A significant cause of flows behind the casing is ineffective mud removal during primary cementing.
The ideal situation is that drilling mud is displaced all around the annulus and that the displacement front advances steadily up the well at the pumping velocity. Even better is that the wide and narrow sides of the front advance at the same speed. Conversely, if the fluid on the narrow side of the annulus does not move, or moves very slowly, a longitudinal mud channel can result. Although the possibility of a narrow side mud channel and benefits of a steady state displacement have been recognised since the mid-1960s, there is still little quantitative understanding of when steady state displacements occur.
In this paper we present new results on the displacement of cementing fluids along eccentric annuli. We show that for certain combinations of the physical properties there will be a steady state displacement front. Furthermore, we are able to give an analytical expression for the shape of the front and indications of how the shape changes with the key physical parameters of the cementing process. These results are novel and have interesting implications for effective mud removal and complete zonal isolation during primary cementing.
High Pressure Nitrogen Injection for Miscible/Immiscible Enhanced Oil Recovery
Authors: Necmettin Mungan 
Published: December 2007

Abstract
High pressure nitrogen injection is being considered as an enhanced oil recovery process for a naturally fractured thick carbonate reservoir containing light oil underlain by an infinite aquifer. The objective is to maintain reservoir pressure at such a level as to increase the ultimate oil recovery economically. In this paper, some of the pre-injection evaluation studies are described. (1). Slim tube displacement tests showed that injecting a small bank of produced C2-C6 hydrocarbon solvent ahead of nitrogen lowered the minimum miscibility pressure (MMP) from 5,300 psi to 3,500 psi, a reduction of about 34 percent. (2). Oil recovery experiments in one meter long, 10 millidarcy permeability homogeneous cores gave an increase of 15 percent in oil recovery at 1.2 pore volumes of nitrogen injection at 3,500 psi injection pressure if miscibility is achieved. (3). A small volume, single well nitrogen injection test in the field resulted in increase of the average daily oil rate by 3 m3 under miscible conditions.