bluuebunny/crossref_metadata_2025_split huggingface dataset:
Waterflooding of Preferential Oil-Wet Carbonates: Oil Recovery Related to Reservoir Temperature and Brine Composition
Authors: Høgnesen E. J. , Strand S. , Austad T. 
Published: December 2007

Abstract
Much effort has been focused on wettability modifying methods to improve the water-wetting nature of carbonates in order to enhance the oil recovery by spontaneous imbibition of water. The use of expensive surface active additives like cationic surfactants of the type R-N(CH3)3+ have been suggested, as well as steam injection. In this study, we will discuss possible wetting modifications of carbonates in relation to potential determining ions present in the injected fluid. Artificial seawater is used as the base or reference imbibing fluid. Outcroup chalk cores of high porosity and low permeability and reservoir limestone cores were saturated with oils with high acid number at residual water saturation to render the cores preferential oil-wet. Spontaneous imbibition tests were performed at different temperatures ranging from 70-130 °C using modified seawater with various concentrations of sulfate, which is regarded as a potential determining ion towards carbonates. Major observations were: (1) Spontaneous imbibition of seawater took place only at elevated temperatures, (2) For the chalk samples, the oil recovery increased beyond the recovery at completely water-wet conditions when the concentration of sulfate was increased 3 times relative to seawater at 130 °C, (3) Reservoir limestone cores also responded with increased oil recovery at 120 °C as the sulfate concentration increased, (4) at lower temperatures, increased spontaneous imbibition was obtained when adding cationic surfactant to the imbibing fluid, (5) The activity of sulfate as a potential determining ion, and thus a wettability modifier, appeared to increase as the temperature is increased. The results show that sulfate is a very efficient wettability modifying agent towards carbonates at elevated temperatures.
Problems Which Can Occur During Coiled Tubing—Case Study: Hassi R'mel Field, Algeria
Authors: Boussa M. 
Published: December 2007

Abstract
Production - Pressure - PLT - RST – GHOST – CBL -Permeability - Porosity - Cement Squeeze - IP
Summary:
A non-rig Coiled Tubing Unit (CTU) cement squeeze technique has been developed and proven since years. This technique does not require that the well be killed. But problems can arrive during the operation and compromise it. For that a study was undertaken on the squeeze cement operation, realized on hassi r'mel field well.
Hassi R'mel field is a gas condensate reservoir with a superposition of three layers A - B - C having very good petrophysic characteristics and a rather significant oil rim in the Eastern and Southern peripheries.
Producing wells were drilled in the Northern part - Central -Southern with two lines of dry gas injection.
Production of water with high salinities disturbed the good production of the wells, which generated negative effects to the gas processing units.
It was necessary to decrease rate of flow of these wells to be able to decrease the volume of water, which generates a loss in the production of gas. In certain case it is necessary to close the well completely.
RST - PLT - GHOST were recorded on these wells to determine the origin of this water influx and a CBL was recorded to see the state of the cement of liners.
Following the results of the operations carried out, a study was undertaken in order to see the method to be used for the optimization of these wells: –Avoid placing a bridge plug for the layer C, because one will lose a good part of production of gas, since this level is more prolific than the other levels.–Isolate the places and perfos which produces water by a cement squeeze.
The purpose of this presentation is to show: –the problems which can occur during operation of coiled tubing; and the reasons of squeeze cement failure.–to show a real case carried out on hassi r'mel field–the advantages and disadvantages of use the coiled tubing.–solutions to adopt to improve the use of coiled tubing.
Case History: Efficient Coiled-Tubing Sand Cleanout in a High-Angle Well Using a Complete Integrated Cleaning System
Authors: Loveland M. J. , Pedota J. 
Published: December 2007

Abstract
As in many oil fields, the primary coiled-tubing (CT) operation in the Kuparuk River Unit on the North Slope of Alaska is a wellbore cleanout. These cleanouts remove produced fines, fracturing sands, scales, and paraffin. As drilling technology advances and wells become longer and more deviated, the process required to clean out these highly deviated wells becomes more complicated. One such case, West Sak Well, is an undulating horizontal well in unconsolidated West Sak sands with a low bottomhole pressure (BHP). During previous attempts with standard cleanout methods, returns were lost during the job and the final results were less than optimal. Post-job reviews of the unsuccessful conventional cleanouts illustrated where previous approaches were insufficient.
This paper describes the use of an integrated cleanout system that efficiently addressed all the challenges of the West Sak Well, which resulted in a successful cleanout returning the well to production. This integrated system approach to wellbore cleanouts was recently commercialized, and this well was the first job using the system in Alaska.
CO2 Capture and Storage in Mature Oil Reservoir: Physical Description, EOR and Economic Valuation of a Case of a Brazilian Mature Field
Authors: Gaspar A. T. F. S. , Lima G. A. C. , Suslick S. B. 
Published: December 2007

AbstractThe mitigation of environmental problems requires both national and international agreements, since they have possible global effects. In nationwide conventions (such as Rio, 92; Kyoto Protocol, 1997), a common conclusion has been the need to reduce greenhouse emissions, especially those due to CO2 from burning fossil fuels. For example, Kyoto protocol has established that industrialized nations should reduce their emissions over 2008-2012 by at least 5.2% compared with the 1990 levels. An alternative USA proposal is based on reducing greenhouse emissions by capturing and stockpiling CO2 in natural sites like oceans, caverns, depleted oil reservoir, etc. This paper presents a physical description and an economic analysis of a project to capture and inject CO2 in oil production and its storage in the depleted oil reservoir located in a mature field in Brazil. The Stella® Software has been used in order to analyze de dynamics of the whole process of CO2 sequestration in enhanced oil recovery, considering each step of the process with its respective energy requirements. The main findings of this have the following benefits: i) reduction in the emission of CO2; ii) extension of the operational life of the reservoir; and iii) improvement and development of technology to promote EOR in mature fields. Results indicate that project NPV is around US$ 3.2 million, what is significant for a small mature field. Additionally, it contributes by removing greenhouse gases (GHG) from the atmosphere by storing 0.73 million tons of CO2 over a period of 20 years. Project feasibility, as expected, was found to be very sensitive to oil price, oil production, and CAPEX.
Capillary Alteration of Shaly Caprocks by Carbon Dioxide
Authors: Chiquet P. , Broseta D. , Thibeau S. 
Published: December 2007

Abstract
The efficiency of the CO2 geological storage process in aquifers and hydrocarbon reservoirs is controlled by several factors. In the case of reservoirs with a shaly caprock, one critical factor is the capillary-sealing potential of the caprock. This potential can be expressed in terms of a maximum storage pressure, equal to the hydrostatic pressure in the caprock plus the CO2 capillary entry pressure in the brine-saturated caprock. It is therefore controlled by the CO2-brine interfacial tension, the water-wettability of shale minerals, and the pore size distribution within the shaly rock.
By means of contact angle measurements, we provide experimental evidence that the water-wettability of minerals representative of shales, such as mica and quartz, is significantly altered in the presence of CO2 under pressures typical of geological storage conditions. Those minerals, known to be strongly water-wet in the presence of oil, turn out to be intermediate-wet in the presence of dense CO2.
We discuss the consequences of such wettability alteration on the maximum CO2 storage pressure, which can be converted into a maximum CO2 height stored in the reservoir. In the case of hydrocarbon reservoirs initially close to capillary leakage, the maximum CO2 storage pressure should be only a fraction of the initial virgin pressure.
Pore- to Field-Scale Multi-Phase Upscaling for IOR
Authors: Lerdahl T. R. , Rustad A. B. , Theting T. G. , Stensen J. Å. , Øren P. E. , Bakke S. , Boassen T. , Palatnik B. 
Published: December 2007

AbstractWe discuss a two-step upscaling workflow to derive field-scale multi-phase flow parameters for depletion. The workflow was designed to increase the quality and reduce the uncertainty related to multi-phase aspects of advanced recovery methods in field-scale reservoir simulation. The upscaling workflow is applied to a realistic model, derived from an element model from the Statfjord field. In a previous paper we have demonstrated that steady-state upscaling yields valid results on the first upscaling step. In this paper, main focus is put on the second step, the transition from a fine-gridded geological model to a coarse-gridded simulation model. We show that in this case our steady-state upscaling tools are presently not able to accurately capture the effects of gravity. A dynamic upscaling (history match) was performed too, and gave a slightly better match. At present, the workflow has a relatively slow turnaround time, but this might be significantly improved by further development and automation of the different methods and tools that are involved. In essence, the upscaling workflow still needs to be improved.
Yard and Field Testing of a Tapered OD Coiled-Tubing System
Authors: Domann R. , Kalman M. , Sharma A. , Stephens R. K. , Chambers M. , Martin J. , McWhorter D. , Melancon J. T. 
Published: December 2007

Abstract
The concept of a tapered outside diameter coiled tubing system (TODCTS) was first presented in 2004.1 This paper laid out the basic requirements for a TODCT system and the advantages of the TODCTS in ultra-deep wells (30,000-ft range). The TODCT system includes: A modified injector that can handle more than one diameter of tubing and maintain a constant grip on the tubing throughout the length of the TODCT string.A "transition tube" that allows sections of tubing with different ODs to be joined together.Well-pressure control equipment (i.e., blowout preventer and stripper) that has the capability to grip and seal more than one diameter of tubing and can also grip and seal the transition tube.An operator control house that allows remote control of the stripper elements and injector gripper elements to open or close to different diameters of tubing while still maintaining control of well pressures inside the wellbore and grip on the tubing.
This paper continues the work that was started previously. A review of the yard testing completed on the equipment is included along with a subsequent field trial done onshore in south Texas. The end result is a tested and qualified TODCT system capable of safely running tubing strings into ultra-deep wells.
A Framework to Design and Optimize Surfactant-Enhanced Aquifer Remediation
Authors: Zhang J. , Delshad M. , Sepehrnoori K. 
Published: December 2007

AbstractSurfactant enhanced aquifer remediation has become an acceptable remediation technology to remove groundwater contaminants such as petroleum hydrocarbons and chlorocarbons. There have been several recent field demonstrations of surfactant remediation where surfactants are used to significantly increase the solubility of the nonaqueous phase liquid (NAPLs) in water. The success of these tests was due to a unified approach using site characterization coupled with a laboratory screening followed by 3D modeling of the process for design and optimization purposes.Here we present the design aspects of the subsurface surfactant flood with the emphasis on the flow and transport modeling. The University of Texas numerical model UTCHEM was used for this purpose. UTCHEM is a three-dimensional, multiphase, multicomponent chemical compositional simulator capable of modeling NAPL migration and groundwater flow and transport in aquifers. Simulations are performed to determine test design variables. These include wellfield configuration and rates, duration of injection and composition of surfactant solution, and hydraulic control achievement using hydraulic control wells.We illustrate an approach to design and optimize surfactant-enhanced aquifer remediation processes in a systematic and efficient manner. To make the approach efficient, a framework that can distribute multiple numerical simulations on a cluster of processors has been successfully implemented. This framework integrates a chemical-enhanced numerical model, UTCHEM, an experimental design methodology, and a Monte Carlo algorithm with a robust global optimization search engine to identify the optimal combination under conditions of uncertainty.
Effect of Coiled Tubing Curvature on Friction Pressure Loss of Xanthan Foams
Authors: Gujar P. V. , Shah S. N. , Zhou Y. 
Published: December 2007

Abstract
This paper presents the results from series of experiments performed to study the effect of coiled tubing (CT) curvature on friction pressure loss of nitrogen gelled foam fluids. A Vi¬in., 10 ft of straight tubing and four sets of coiled tubing with curvature ratio (r/R) values of 0.01, 0.019, 0.031, and 0.075 are used in the experiment. A set of tests are performed using 20 and 30 lb/Mgal xanthan gum as base fluid and 0 to 80% quality nitrogen xanthan foams. Friction pressure data are gathered by monitoring the pressure drop across a 10-ft straight section and a given CT simultaneously. All data are gathered at ambient conditions and at a system pressure of 1000 psi. It is found that the friction pressure losses of nitrogen gelled foams in CT are significantly higher than the straight tubing even at low Reynolds number. The extent of CT curvature determines the magnitude increase in friction pressure loss. Empirical correlations for the prediction of friction pressure loss of gelled foams in both the straight and coiled tubing are developed for laminar, transition and turbulent flow regime. These are based on the dimensionless quantities of Fanning friction factor and generalized Dean number.
Efficient Closed-loop Production Optimization Under Uncertainty
Authors: Sarma P. , Durlofsky L. J. , Aziz K. 
Published: December 2007

AbstractThis work discusses a closed-loop approach for efficient real-time production optimization that consists of three key elements – adjoint models for efficient parameter and control gradient calculation, polynomial chaos expansions for efficient uncertainty propagation, and Karhunen-Loeve (K-L) expansions and Bayesian inversion theory for efficient real-time model updating (history-matching). The control gradients provided by the adjoint solution are used by a gradient-based optimization algorithm to determine optimal control settings, while the parameter gradients are used for model updating. Polynomial chaos expansions provide optimal encapsulation of information contained in the input random fields and output random variables. This approach allows the forward model to be used as a black box but is much faster than standard Monte Carlo techniques. The K-L representation allows for the direct application of adjoint techniques for history matching while assuring that the two-point geostatistics of the reservoir description are maintained. The benefits and efficiency of the overall closed-loop approach are demonstrated through real-time optimizations of net present value (NPV) for synthetic reservoirs under waterflood subject to production constraints and uncertain reservoir description. The closed-loop procedure is shown to provide a substantial improvement in NPV over the base case, and the results are seen to be very close to those obtained when the reservoir description is known apriori.
Productivity of Frac Stimulations in the German Rotliegend: Theoretical Consideration and Practical Results
Authors: Koehler M. 
Published: December 2007

Abstract
The main production of German gas fields is from sandstones of Upper Rotliegend age (Permian period). The Upper Rotliegend is characterised by a sequence of sandstones, siltstones and shale beds. Most of the present gas fields produce from low permeability layers (mainly 0.1-20mD) in a high pressure and high temperature environment. Hydraulic fracture stimulation has been developed to a regular completion concept in the last 15 years. Fracture stimulations, if applicable, are planned in all new drilling projects as a standard procedure to enhance the productivity of a well.
Due to the nature of the Upper Rotliegend depositional environment, a vertical to horizontal permeability anisotropy of about 1/10 can occur within the sandstones. Hydraulic fracture stimulations, in comparison to perforations, have proven to (i) bridge vertical flow barriers within sandstone/ siltstone sequences as well as (ii) to improve the connectivity of the stimulated layers horizontally. The result is an overall permeability capacity increase, vertically as well as horizontally. In addition, the effective productivity index enhancement pre and post frac, the fold of increase (FOI), is usually higher than theoretically expected from hydraulic fracturing.
Based on an "effective wellbore radius concept" to calculate the inflow performances of a fractured well, sensitivity studies were carried out to investigate the stimulation treatment results under different reservoir conditions. The main parameters, which have an impact on the fold of increase, are discussed. Based on transient well test analysis, 20 fracture treatments are compared with a theoretical radial inflow model with respect to their expected and observed productivity enhancement.
Development, Verification, and Improvement of a Sediment Toxicity Test for Regulatory Compliance
Authors: Dorn P. B. , Rabke S. , Glickman A. , Louallen J. , Nguyen K. , MacGregor R. , Candler J. , Wong D. C. L. , Hood C. , Hall J. , Purcell T. 
Published: December 2007

AbstractThe offshore oil and gas industry has moved toward the use of synthetic-based drilling fluids (SBF), changing potential exposure scenarios for discharged cuttings when compared to those of water-based drilling fluids (WBF). Unlike WBF, SBF sorbs predominately to particles in the cuttings and are not dispersed extensively into the water column, therefore, a sediment toxicity test was required by the US Environmental Protection Agency (US EPA) in addition to the existing water column test to define a best available technology (BAT) limit. Inclusion of a sediment toxicity test for NPDES compliance was precedent setting and unique. In order to fulfill the US EPA requirements, an inter-industry research group worked with EPA to develop a suitable test that met the technology-based discharge standard. Toxicity of discharged field drilling fluid is compared to a reference SBF (C1618 internal olefin) and, for compliance, the ratio of the reference drilling fluid median lethal concentration (LC50) to the field mud LC50 must be ≤1.0. Prior to its use, there were concerns that false positive results could cause incorrectly identified non-compliance events, limiting the use of SBF technology. Consequently, initial application allowed the use of a variability (K) factor in determining the ratio. After initiation as a compliance test, research was continued to reduce test variability and minimize false positives. That research included: 1) analysis of NPDES compliance data (500+ tests), 2) two inter-laboratory testing programs, 3) analysis of reference fluid data from one commercial laboratory, and 4) refinements to test sediment type and animal health. The results of these efforts to date are reviewed in this paper and are used to identify potential improvements in the application of the test as a regulatory tool.
Alaska Regulatory Guidelines for Qualification of Multiphase Metering Systems for Well Testing
Authors: Williamson J. , Mehdizadeh P. 
Published: December 2007

Abstract
Alaskan operators are investigating multiphase meter (MPM) use in well testing and field production allocation. The Alaska Oil and Gas Conservation Commission (AOGCC) is requiring approval prior to use of multiphase meters for production allocation purposes. The AOGCC prepared guidelines(1) and an accompanying technical primer(2) to aid Alaskan operators in gaining approval of MPM use. This paper provides the background for the development of the AOGCC guidelines and the expected role these guidelines will play in the approval of novel multiphase metering technology for well testing.
Automating Continuous Steam Injection in the Diatomite Formation, Midway Sunset Field, California
Authors: Holtzclaw J. I. , Branson Aubrey G. 
Published: December 2007

Abstract
This paper shows a successful automated system to control both steam rate and pressure in the heavy oil diatomite formations in the Midway Sunset field. Diatomite reservoir permeability is usually less than 10 md with naturally occurring fractures that promote premature steam breakthrough. In addition, this location was extremely shallow with the chance of surface steam eruption. The new system optimizes steam injection while controlling rapid pressure rise which could cause serious problems such as steam channeling and eruption out of zone.