bluuebunny/crossref_metadata_2025_split huggingface dataset:
Compositional Modeling of Oil-Based Mud-Filtrate Cleanup During Wireline Formation Tester Sampling
Authors: Alpak F. O. , Elshahawi H. , Hashem M. , Mullins O. 
Published: December 2007

Abstract
Miscible oil-based mud (OBM) filtrate contamination poses a major challenge to the acquisition of representative fluid samples using wireline formation testers (WFTs). A sound understanding of the physics of OBM filtrate clean-up and identification of first-order impact parameters is of paramount importance for the design of new generation WFT probes that can operate in OBM filtrate environments with enhanced efficiency.
Analytical as well as numerical models reported in the formation testing literature rely predominantly on simplifying assumptions in terms of the compositions of flowing fluid phases. These models characteristically assume single-component phases in the case of two-phase immiscible formulation, or a two-/three-component hydrocarbon phase in cases of black-oil/extended black-oil formulations. In turn, compositional interactions are entirely neglected or represented through simplistic empirical correlations. Such conventional models are deemed sufficient for pre-job planning and interpretation of measurements acquired in formations subject to water-base mud (WBM) filtrate contamination. Dynamics of flow in OBM filtrate contaminated formations is significantly more complex. A time-dependent coupling between fluid dynamics and phase behavior constitutes the governing physics of OBM filtrate clean-up process. Therefore, for OBM filtrate environments, accuracy of conventional formulations in representing the actual physics of flow is limited.
We have constructed a numerical model for the OBM filtrate clean-up within the framework of an equation-of-state (EOS) compositional fluid-flow simulator. Our numerical framework simultaneously honors the physics of multi-component fluid flow and the thermodynamics of phase behavior. The numerical model was verified against analytical solutions for zeroth-order models for which analytical solutions exist. Simulation results exhibited close agreement with the analytical predictions and with field data for the time dependence of contamination during sampling. A rapid approximate response surface based model, which can serve as a pre-job planning or real-time analysis tool, was derived from extensive simulations conducted with the compositional numerical model. Our simulation and rapid modeling results compare well with empirical observations made in the field. In particular, the rate of change of miscible contamination with time has been found empirically to vary as t5/12. For the first time, modeling has been shown to give essentially the same results as empirical observations. The agreement between our model and common field observation motivates use of our model to analyze the more complex WFT probes, which have recently become available.
Efficient Cost Saving through an Appropriate Completion Design
Authors: Ouyang L. -B. , Huang W. S. , Dickerson R. 
Published: December 2007

Abstract
Well completion plays a critical role in the performance of a well in its entire life. More and more advanced well completion options are available for potential deployment in new wells, especially those in deep water and offshore; however, the cost could vary significantly from one completion type to the other. Considering the fact that completion takes a substantial stake in the whole CAPEX for a new well, the cost and the impact of the well completion is too significant to be ignored.
Two field case studies will be discussed in the present paper to demonstrate the possibility of cost saving through efficient completion designs. The first case study is focused on a deviated gas producer, and the second on a horizontal oil producer. The most popular completion options, including openhole gravel pack, cased-hole gravel pack, openhole, standalone screen, cased-hole frac pack, expandable sand screen, inflow control devices (ICD), intelligent well completions (DIACS), etc, will be considered in the completion selection. Other completion options such as alternating standalone screen and blank pipe that may slash completion cost without sacrifice of well performance will also be proposed and evaluated. Well performance will then be evaluated in details by assessing total well production, annular flow and flow inside the liner/tubing, pressure profiles along the annulus and along the liner, inflow from reservoir to annulus and fluid transfer between annulus and liner, and so on. Cost recovery, water and/or gas shut-off, formation damage, casing collapse, sand prevention issues associated with different completion options will be addressed.
A work flow aiming at optimizing well performance while maintaining completion cost at the minimum will be proposed.
The Eureka Canyon Oil Field: A Case History
Authors: Hesson B. H. 
Published: December 2007

Abstract
The Eureka Canyon oil field is one of the oldest in Ventura County, California. The approximately 920-acre field was discovered in 1893 due to the presence of natural oil seeps. The field is near the City of Piru, south of State Highway 126 and the Santa Clara River, with the wells located in two canyons named Smith and Eureka. Many of the field’s 112 wells were drilled using cable tool rigs. T.E.G. Oil & Gas USA, Inc. (TEG) produces 16 barrels of oil per day from eight wells in Smith Canyon, with production from the Miocene formation found at an average depth of 1,800 feet. Due to marginal production, the wells in the Eureka Canyon area of the field were plugged and abandoned or left orphaned when the last operators-of-record became defunct. Some of these wells are in a remote, steeply sloped area of Eureka Canyon that became inaccessible over time due to erosion and the dense growth of chaparral.
Wild fires rampaged through Ventura County in October 2003, impacting 24 oil fields, including Eureka Canyon. While conducting field inspections following the fires to assess damage and during subsequent well work, the Division of Oil, Gas, and Geothermal Resources (Division) located and identified 17 previously inaccessible orphan wells, 13 without wellheads. As a safety and spill prevention measure, the Division secured these wells. Record rainfall in 2005 washed out lease roads and compromised some of the well locations due to mud and rockslides. Since TEG was not interested in acquiring these orphan wells, and six others for a total of 23 wells, the Division contracted to have them plugged and abandoned. This paper will present a brief field history and describe the Division’s efforts to locate, identify, secure, and abandon these wells.
Using Synchrotron Radiation Wide-Angle X-Ray Scattering (WAXS) to Study the Inhibition Effect of DiEthyleneTriaminePenta (MethylenePhosphonic Acid) (DETPMP) on CaCO3 Scale Formation
Authors: Chen T. , Neville A. , Sorbie K. , Zhong Z. 
Published: December 2007

Abstract
The formation of calcium carbonate mineral scale is a persistent and expensive problem in oil and gas production. Scaling of metallic or insulating walls in contact with hard water may cause unscheduled equipment shutdown and loss of production. The aim of this paper is to further the understanding of scale formation and inhibition by in-situ probing of crystal growth by synchrotron radiation Wide Angle X-Ray Scattering (WAXS) in the absence and presence of diethylenetriaminepenta (methylenephosphonic acid) (DETPMP) scale inhibitor at elevated temperature and high pressure. This novel technique enables in-situ study of mineral scale formation and inhibition and as such, information on the nucleation and growth processes is accessible. This technique studies bulk precipitation and surface deposition in the same system and has great benefit to understand an industrial scaling system. It offers an exciting prospect for the study of scaling.
It has been shown that the nucleation and growth of various calcareous polymorphs and their individual crystal planes can be followed in real-time and from this the following conclusions are reached.
❖ The process of scale deposited on the surface can be divided into an unstable phase and a stable phase. The initial phase of crystallization of calcium carbonate is characterized by instability with individual planes from various vaterite and aragonite polymorphs emerging and subsequently disappearing under the hydrodynamic conditions. After the initial unstable phase, various calcium carbonate crystal planes adhere on the surface and then grow on the surface. ❖ DETPMP has a profound effect on the induction time of the surface deposit. It inhibits scale crystal adhesion onto the surface, although the bulk precipitate is observed in the scaling system. It displays different inhibition mechanisms for bulk precipitation and surface deposition inhibition. ❖ DETPMP inhibits surface deposition. It suppresses calcite formation and results in the least stable vaterite crystal formation.
This paper will discuss how surface scale evolves in the absence and presence of the inhibitor - exploring the power of the synchrotron in-situ methodology.
Evaporative Recovery of Trapped Oil in Fractured Reservoirs: A Pore-Network-Level Analysis of Capillary and Gravity Effects
Authors: Tajer S. E. , Yortsos Y. C. 
Published: December 2007

Abstract
The recovery of volatile oils from the matrix of fractured porous media can be significantly aided through gas injection. Within certain assumptions, this process operates much like the isothermal drying of porous media. For example, recovery is controlled by mechanisms involving capillary, viscous and gravity forces in the liquid and the liquid-gas interfaces, and mass diffusion and convection in the gas phase.
In this work the effect of capillarity and gravity driven viscous flow through macroscopic liquid films during the isothermal drying of porous materials is studied. We use a mathematical model based on a 2-D pore-network representation of porous media. The problem is characterized by two dimensionless parameters, a diffusion-based Capillary number, Caf, and the gravity Bond number, Bg, in addition to the various geometrical parameters of the pore network. The simulator accounts for evaporation and diffusion of a volatile liquid, trapped in a heterogeneous pore network.
Results on the evolution of the liquid saturation, the isolated liquid clusters and the drying rates are obtained as a function of dimensionless time and the dimensionless parameters in the two cases when gravity opposes or aids the process (corresponding to positive or negative Bond numbers, respectively). In the first case, the fronts are stabilized, while in the second they are destabilized. It is shown that gravity-controlled film flow is a major transport mechanism in the drying of porous media, its effect being dominant when gravity and capillarity control the process. Under strong capillarity conditions, the films span across the whole block, enhancing significantly liquid flow from distant clusters and improving recovery rates.
The paper finds application to the recovery of volatile oils from fractured or heterogeneous reservoirs by gas injection.
Estimating Layer Properties for Wells in Multilayer Low-Permeability Gas Reservoirs by Automatic History-Matching Production and Production Log Data
Authors: Spivey J. P. 
Published: December 2007

Abstract
Most of the major unconventional gas plays in the U.S. have multiple productive intervals. Wells are completed with multiple fracture treatments, and are produced commingled. This paper describes a new fully-coupled reservoir/wellbore single-well analytical simulator* for multilayer unconventional gas reservoirs that automatically history matches production and production log data simultaneously.
The layers in the simulator are independent, with different temperatures, pressures, completion types, and reservoir geometries. The simulator rigorously accounts for transient and boundary-dominated flow in each layer and pressure drop in the wellbore, including pressure drop between adjacent layers and pressure drop from the reservoir to the surface.
By history matching data from multiple production logs as well as surface production data, the simulator provides accurate estimates of individual layer properties such as permeability, fracture length, and drainage area. The simulator may be used for reservoir and fracture treatment evaluation, restimulation candidate selection, fracture design optimization, and performance forecasting in multilayer unconventional gas plays.
Effect of Hydrate Inhibitors on Calcite, Sulfates, and Halite Scale Formation
Authors: Shipley H. J. , Kan A. T. , Fu G. , Shen D. , Tomson M. B. 
Published: December 2007

Abstract
Methanol is a common industrial solvent and is added to water to enhance hydrocarbon solubility and to prevent solid hydrate from forming, as well as other applications. One of the side effects of methanol addition to water is it greatly reduces the solubility of ionic solids, particularly divalent solids. The effect of methanol on ionic solubility has been reported only for a few isolated conditions. The effect of hydrate inhibitors on oilfield scale formation has been studied. A semi-empirical approach is proposed to correlate the effect of hydrate inhibitors on scale formation and inhibition from experimental solubility measurements of halite, barite, gypsum, calcite and carbonate equilibrium chemistry. The ion-cosolvent activity coefficients can be used directly in any solution speciation code to evaluate the effect of cosolvent on mineral scale formation. The validity of the equation has been tested between 4-200°C and 1-6 M ionic strength. Barite solubility is significantly reduced, by as much as 20 fold, with 50% (v/v) methanol. Other mineral solubilities are also reduced significantly. Ethylene glycol has much less impact on mineral solubility than methanol. Good agreements between the model prediction versus both experimental and literature results are observed.
A New Cementing Approach to Improve and Provide Long-Term Zonal Isolation
Authors: El-Marsafawi Y. , Al-Yami A. , Nasr-El-Din H. A. , Al-Jeffri A. , Misran M. , Hasan A. , Jain B. 
Published: December 2007

Abstract
A new cement system has been developed to meet oil and gas industry's need for better zonal isolation. In this paper, we present design, execution, and evaluation of the system used to cement solid expandable tubular (SET) in a carbonate field in southern Saudi Arabia. The SET is 900-ft long with 5½-in. diameter, placed horizontally in a 7½-in. drilled hole with a 9,000-ft depth. To enhance well production, two windows were milled from inside the cemented SET to drill laterals to maximize surface contact with the horizontal oil reservoir.
Special laboratory techniques were used to evaluate set-cement and slurry properties of the system to determine its potential use for field application. Distinguishing features of the developed versus conventional cement are also explained.
Pressure and inflow tests were used along with cement evaluation tools to evaluate the success of the operation. Production profile was also studied to ensure durability of the cement system.
Precipitation and Dissolution of Minerals During Waterflooding of a North Sea Oil Field
Authors: Houston S. J. , Yardley B. W. D. , Smalley P. C. , Collins I. 
Published: December 2007

Abstract
A long-term study of produced water chemistry from a North Sea field was used to investigate the mechanisms of water mixing and water-rock interaction in the reservoir. Seawater flooding has continued throughout much of the production life. Detailed repeated sampling of the produced water was undertaken and has produced an extensive dataset, yielding information on water chemistry variations in space and time. The dataset documents both fluid mixing in the field and the physical, chemical and thermodynamic response of the system to the injection of seawater. Analysis of the data establishes the nature of the controls on the composition of the scale-prone formation water, and enables an in-depth look at the fluid-rock interactions occurring in the reservoir during a waterflood.
Changes in produced-water chloride concentration through time reflect changing proportions of injected seawater and formation-water, revealing differing patterns of injected-water breakthrough over the field. However, parallel changes in the concentrations of less conservative fluid components provide evidence of fluid-mineral interactions that occurred in the reservoir on the timescale of the waterflood. For example, calcium is enriched in the produced fluid relative to a linear mixture of original formation-water and seawater, while magnesium is depleted, probably reflecting dolomitisation of calcite and growth of clay. Barium and sulphate are strongly depleted due to precipitation of barite. However, mass balance highlights an additional sink for sulphate, possibly reduction to sulphide. Excess silica present in the produced fluid is ascribed to dissolution of silicate phases in the reservoir. Concentrations demonstrate that the produced water is always close to quartz saturation at reservoir temperature, irrespective of the proportion of seawater produced.
Analysis of produced water chemistry provides insights into the inner workings of the reservoir system during a waterflood. Study of individual dissolved species relative to linear mixing lines between injected and formation water allows measurements of the nature and amounts of dissolution and precipitation reactions affecting scaling ions within the reservoir. This allows for greater understanding of the controls on water composition and of the nature of water mixing in the reservoir, leading to improved prediction and planning of scale occurrence, prevention and remediation.
Simulating Calcium Naphthenate Formation and Mitigation Under Laboratory Conditions
Authors: Dyer S. J. , Williams H. L. , Graham G. M. , Cummine C. , Melvin K. B. , Haider F. , Gabb A. E. 
Published: December 2007

Abstract
A laboratory methodology has been developed to better simulate calcium naphthenate formation and evaluate chemical inhibition measures. Detailed ongoing field experience data and related samples have been used in support of the lab rig design and protocols.
Calcium Naphthenates are becoming more recognized as a major flow assurance issue. When occurring in the field operation, significant quantities (typically in tonnes per day) can be formed and the process operation, chemical controls and monitoring procedures are far from straightforward. The ability to accurately predict calcium naphthenate formation and/or replicate field production conditions in the laboratory has been fraught with difficulties. For example conventional "bottle" or "jar" test procedures suffer from severe limitations relating to poor pH control, inefficient mixing, non representative residence times coupled with relatively indirect assessments often indicating fluid compatibility issues rather than identification of naphthenate deposits.
Recent work examining both current calcium naphthenate problems in existing facilities and the technical requirement to predict the potential for naphthenate deposits in new fields has led to the design and validation of more appropriate laboratory test equipment. This includes new designs of novel dynamic flow systems and modified autoclave approaches which allow the formation of naphthenate deposits, stable emulsions and soap scales to be assessed directly under laboratory conditions using relatively small volumes of reservoir fluids. The designed equipment is shown to overcome the challenges previously associated with the assessment of calcium naphthenate issues, their mitigation and chemical treatment under laboratory conditions.
The ability to simulate naphthenate deposition represents a major step forward in our ability to understand the controlling parameters associated with these complex scales. This paper will describe the novel aspects associated with the laboratory flow rig and other test methods adopted, it will illustrate how the equipment design overcomes the limitations associated with more conventional tests and describe how the results are being used directly to assess the changing naphthenate challenge and its treatment which may be expected throughout a field's lifetime. The composition of solids collected from naphthenate formation tests in the flow rig under different conditions is also presented, thus further validating the effectiveness of the rig design. The paper therefore illustrates how improved equipment design and test protocols can reduce the risks associated with field trials, which have previously been required for optimising treatments against naphthenate deposits.
Automated Liquid Unloading in Low-Pressure Gas Wells Using Intermittent and Distributed Heating of Wellbore Fluid
Authors: Alipour-Kivi G. , Bugacov A. , Khoshnevis B. , Ershaghi I. 
Published: December 2007

Abstract
This paper presents a comprehensive simulation study demonstrating technical merits of automatic intermittent and distributed heating for reducing back pressure and maintaining flow in low pressure gas wells.
Reduction or elimination of the additional wellbore backpressure plays a key role in boosting gas wells productivity and extending the lifetime of the field. The backpressure is mostly due to the development of excess liquid water along the tubing stopping the low pressure gas flow. We present two-phase thermal flow simulations to study the impact of intermittent volumetric heating along the wellbore to reduce or eliminate the excess backpressure caused by either water condensation in the upper part of the wellbore, or the overall increase of density of the two-phase fluid. The proposed method helps in continuous prevention of the excess water development enabling the well to produce without interruption up to its natural limit.
Modeling the thermal exchange in the wellbore, two-phase flow pressure simulation demonstrates that flowing and thermo-dynamic conditions of the water/gas mixture along the wellbore have a substantial impact on the overall backpressure. Our results show that by modifying the thermal profile of the wellbore fluid at specific locations and times, we can maintain significantly lower backpressures and increase well productivity. Our case studies highlight that for very low pressure gas wells, the external power requirements can be more acquiescent to automation and control than the existing methods.
The results yield valuable insight in the development of a novel liquid unloading techniques based on volumetric heating of the wellbore fluid. Our results can also be applied to the elimination of hydrates in gas wells.