bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Assessment of Adhesion of Scale and Electrochemical Pre-treatment for the Prevention of Scale Deposition on Metal Surfaces
Authors: Labille S. , Neville A. , Graham G. M. , Boak L. S. 
Published: December 2007

Abstract
From an oilfield scale prevention perspective, interest recently has focused on understanding the relationship between heterogeneous nucleation and growth on pipeline surfaces (adhesion) rather than homogeneous nucleation and growth from bulk solution. Furthermore, it is recognised that homogeneous nucleation, and not adhesion, is conventionally examined in industry standard bulk "jar" type tests for the assessment of scale inhibitor performance. The trend towards understanding heterogeneous nucleation and growth has gained interest because scale adhesion is recognised as a much more serious issue than homogeneous "bulk" precipitation.
In a recent paper by Neville et al.1 a novel electrochemical approach, has been described which enabled the extent and also the rate (kinetics) of CaCO3 and BaSO4 scale formation on a solid surface to be determined. During this study it was clearly shown that the formation of an inhibitor film at a metal surface can occur and the extent of this is affected by the presence of certain cations, the inhibitor concentration and the hydrodynamic and electrode potential regimes. In laboratory studies on rotating disk electrode (RDE) coupons it has been clearly demonstrated that this film has a beneficial effect in preventing scale formation from a supersaturated solution onto a metal surface.2,3 As such there is potential to enhance scale inhibition by carrying out an electrochemical pre-treatment.
In this paper the research has been extended to include pre-treatment of surfaces in a dynamic tube-blocking rig. The effect of various pre-treatment parameters on carbonate scale have been assessed and it has been shown that even in the higher temperature and pressure environment there is a benefit of using electrochemical pre-treatment.
In addition, the paper summarises other work conducted by the authors which examines the relationship between heterogeneous nucleation and growth on pipeline surfaces (adhesion) rather than homogeneous nucleation and growth from bulk solution which includes the impact of conventional scale inhibitors and film forming corrosion inhibitors.
Lessons Learned from Descaling Wells in a Sandstone Reservoir in Saudi Arabia
Authors: Nasr-El-Din H. A. , Lynn J. D. , Hashem M. K. , Bitar G. E. , Al-Ali A. A. 
Published: December 2007

Abstract Description of Paper
This paper describes the development and field application of an acid-based treatment to remove downhole scale in several oil producing wells in a sandstone reservoir in Central Saudi Arabia. The sandstone reservoir is weakly consolidated and sanding problems were noted in several wells. To avoid sanding problems, these wells were gravel packed. In addition, the reservoir pressure and gas oil ratio are low and, as a result, electrical submersible pumps (ESP) are used to produce these wells. The sandstone reservoir contains 1-13.5 wt% clay minerals and the bottom hole temperature is 160°F. A thorough investigation was undertaken to identify the composition and location of the scale, to recommend a suitable acid formulae to remove the scale, and to assess the effectiveness of the treatment in the field.
Based on extensive lab studies, an acid treatment was designed and applied in more than 15 wells. These wells have a water cut that ranges from 3 to 80 vol%. Because of the low reservoir pressure, these treatments were conducted using coiled tubing and the spent acid was lifted using nitrogen gas. In addition, the formation is water-sensitive. Therefore, the pre and post flushes were designed to minimize formation damage due to fines migration and clay swelling. Chemical analysis of acid returns (spent acid) was used to determine the type and concentration of acid additives.
HPHT Wells Create New Challenges Demanding Higher Levels of Coiled Tubing Inspection and Management
Authors: McCoy T. , Rosine R. , Aulert C. , Martin J. , Stanley R. K. 
Published: December 2007

Abstract
The coiled tubing (CT) industry continues to operate in deeper and higher-pressure wells.1 Under these demanding service conditions, performance and reliability of the tubing are essential. This paper discusses field service and other events that led to an aggressive plan to introduce new inspection techniques that will help assure a higher level of performance of coiled tubing strings. The enhanced inspection techniques being instituted include inspection by the tubing manufacturer of the incoming strip and continuous phased-array ultrasonic inspection of the seam weld. In addition, the traditional through-hole calibration standards were upgraded with more realistic discontinuities to help ensure that the produced tubing is defect-free. The paper also discusses the important requirements of string management and maintenance procedures. A key to the success of this ongoing program has been the synergistic activity between the service company and the tubing manufacturer.
Intelligent Wireless Orienter for Coiled Tubing Drilling: Development to Field Test
Authors: Zegarra Erica , Meek Dale , Udo Cassee , LeBlanc Joey , Hearn David , Johnson Mark 
Published: December 2007

Abstract
A critical requirement for directional drilling with coiled tubing (CT) is a reliable downhole means to manipulate the orientation of the mud motor bend. Alaskan operations have traditionally used hydraulically actuated ratcheting orienters, thus avoiding the complications of wireline and control lines inside the coiled tubing. With highly refined field techniques and well plans, the fundamental drawbacks to these orienters have been adeptly managed on the North Slope.
Despite good success over the years, drilling and orienting have remained mutually exclusive activities. As such, orienting becomes nonproductive time (NPT) when it cannot be combined with necessary hole conditioning and wiper trips. While orienting problems and failures have been increasingly common in deep and high-build-rate applications, perhaps the most significant challenge to the standard hydraulic orienter service for coiled tubing drilling (CTD) is lost circulation.
Initial steps in the development of an intelligent wireless orienter for CTD were taken in 1999 with the goal of eliminating off-bottom orientation, a significant source of NPT for Prudhoe Bay operations. Subtle computer-controlled mud pump variations are the basis for a versatile downlink command structure used to drive the downhole actions of the turbine orienter. The benefits of the prototype orienter were confirmed during a promising field trial beginning in late September 2001. As of December 2001, the novel service has been used on eight wells in Prudhoe Bay. This paper describes the turbine orienter development program, testing, a quantification of benefits, reliability figures, lessons learned, and future plans.
Underbalanced Coiled-Tubing Technique Leads to Improved Productivity in Slotted Liner Completions
Authors: Hibbeler Jeff , Duque Luis , Castro Luis , Gonzalez Alexis , Romero Jorge 
Published: December 2007

Abstract
Sand production is a well-known and costly problem in shallow unconsolidated sands. For years slotted liners have been used to control sand in these types of reservoirs. However, over time sand, fines and other debris can clog slots or make their way into the liner itself, thus blocking production. A new live-well intervention technique making use of a concentric coiled tubing (CCT) vacuum tool (VT) has been implemented in Venezuela1,2,3. The technique incorporates a venturi jet pump mounted on CCT, and is specifically designed to remove solids and/or fluids from the wellbore without placing hydrostatic loads on the reservoir. In sand vacuum mode, strong jets fluidize and mobilize solids into the vacuum as well as prevent a stuck pipe scenario. The jets also aid in opening clogged slots by loosening fines that may be blocking flow. When the VT applies suction, a localised pressure-influenced-zone is formed in the very near wellbore – thus providing an isolated ";point-load"; drawdown on the formation.
The jetting action combined with point-load drawdown and drag forces results in solids removal from behind pipe as well as inside pipe. Evidence of this phenomenon are jobs where a solids volume greater than the entire liner has been retrieved to surface. Post job results on jobs performed in Venezuela consistently show reduced skin, increased Productivity Index (PI) and higher long-term oil production.
This paper describes the latest in CCT vacuum technology as well as it improvement in time via case studies of several different applications in Venezuela. Also discussed are simple lab techniques, which reveal serious completion issues such as liner slot erosion, fines invasion and drilling fluid damage.
Field Application of Relative Permeability Modifier in Venezuela
Authors: Nieves Gustavo , Fernandez Jenny , Dalrymple E. Dwyann , Sierra Leopoldo , Eoff Larry , Reddy B. R. 
Published: December 2007

AbstractFor many years, relative permeability modifiers (RPM's) have received a great deal of attention from the oil and gas industry. Because of the completion techniques used in many wells, protecting the hydrocarbon interval properly during a watershutoff treatment is not always practical or cost effective. RPM's offer the option of bullheading a treatment without zonal isolation, which is designed to decrease water production with little or no decrease in oil or gas production.This paper describes the laboratory development and optimization of a polymeric RPM. The resulting material can best be described as a brush polymer consisting of a polymeric backbone grafted with methoxypolyethylene glycol (MPEG). Various phases of the development are discussed, and an overview of the laboratory evaluations is also provided. These test results indicate that the RPM polymer should be placed with a systematic approach consisting of proper preflushes and post-flushes for optimum results. A field case study in which the system was used in Venezuela is provided, along with the subsequent results of the treatment.
The Effect of Heterogeneity on In-Situ Combustion: The Propagation of Combustion Fronts in Layered Porous Media
Authors: Akkutlu I. Yücel , Yortsos Yannis C. 
Published: December 2007

Abstract
Large fractions of heavy oil reserves remain in shallow reservoirs, consisting of relatively thin sands separated by nearly impermeable shales. A potential recovery method for heavy oil is in-situ combustion. Compared to other methods, in situ combustion involves the added complexity of exothermic chemical reactions and temperature-dependent kinetics. Previous theoretical work by the authors have focused on the process in a single layer [7]. In this paper we try to extend the approach to heterogeneous systems, by considering the simpler case of in-situ combustion in layered porous media (and particularly to a two-layer model). Analytical models are developed to delineate the combined effects of uid ow, reaction and heat transfer on the dynamics of combustion fronts in layered porous media, using as parameters the thermal coupling between the layers, the heat transfer to the surroundings and the permeability contrast. We find that in layered systems, the thermal coupling between layers leads to coherent traveling fronts, propagating at the same velocity. This coupling retards greatly fronts in the more permeable layers and accelerates only slightly those in the less permeable ones, until a common front velocity is attained. As in the single-layer case, there exists a unique solution, under adiabatic conditions, and multiple steady-state solutions, under non-adiabatic conditions. The latter lead to ignition and extinction conditions. We show that the layer thickness and the permeability contrast between the layers play a crucial role. Importantly, for a sufficiently large permeability contrast, relatively small layer thickness and under non-adiabatic conditions, steady-state propagation in the two layers cannot be sustained, and the process becomes extinct, even though, under the same conditions, sustained propagation would have been predicted for the equivalent single-layer problem with the average injection velocity. Simple constraints are derived to delineate this case. The analysis is useful for the understanding of the viability of in situ combustion in heterogeneous porous media.
Production Acceleration and Injectivity Enhancement Using Steam-Propane Injection for Hamaca Extra-Heavy Oil
Authors: Rivero J. A. , Mamora D. D. 
Published: December 2007

Abstract
Experiments were conducted to study the feasibility of using propane as a steam additive to accelerate oil production and improve steam injectivity in the Hamaca field, Venezuela. The experiments utilized a vertical injection cell into which a mixture of sand, oil and water was tamped. The Hamaca oil sample had an oil gravity of 8°API and a viscosity of 25,000 cp at 50°C. The injection cell was placed inside a vacuum jacket, set at the reservoir temperature of 50°C. Superheated steam at 170°C was injected at 3.5 ml/min (cold-water equivalent) simultaneously with propane at the top of the cell. The cell outlet pressure was maintained at 50 psig. Four propane:steam mass ratios were used, namely, 0:100 (pure steam), 2.5:100, 5:100, and 10:100. Produced liquid samples from the bottom of the cell were collected, treated to break emulsion, and analyzed to determine oil and water volumes, and density and viscosity of the oil. The oil was subjected to SARA analysis to determine the degree of in-situ oil upgrading. Composition of the produced gas was determined using a gas chromatograph. Each run lasted three hours.
Experimental results indicated the following. First, with steam-propane injection, start of oil production was accelerated by 17% compared to that with pure steam injection. In the field, this could translate into significant gains in discounted revenues and reduction in steam injection costs. Second, steam injectivity with propane as an additive was up to three times higher than that for pure steam injection. Third, oil production acceleration and injectivity increase were practically the same for runs with propane as a steam additive (irrespective of the propane:steam mass ratios). Propane appears to be a viable steam additive at propane:steam mass ratios as low as 2.5:100.
Improved Measurement of Gas Diffusivity for Miscible Gas Flooding Under Nonequilibrium vs. Equilibrium Conditions
Authors: Civan Faruk , Rasmussen Maurice L. 
Published: December 2007

AbstractPhysically and mathematically rigorous improved models, considering equilibrium and nonequilibrium diffusion gas transport in the liquid phase and resistance of the gas-liquid interface to gas dissolution in liquids, are developed. This allows the accurate determination of the gas diffusion coefficient from experimental measurements of the gas pressure decline in a closed tank by dissolution of gas in the liquid. The short- and long-time solutions of these models are derived analytically under various conditions. These solutions are reformulated for direct determination of the best estimate of the diffusion coefficient by regression of the resultant analytical expressions to experimental data. Procedures are presented and demonstrated for accurate estimation of the gas diffusivity coefficient by conforming the present models to experimental data.The results developed in this paper can be utilized for determination of the gas diffusivity and the rate of dissolution of the injection gases used for secondary recovery and the rate of separation of light gases from reservoir oil and brine. The present analytic expressions can be facilitated to establish the significance of the equilibrium vs. nonequilibrium conditions under in situ conditions for gas injection, including carbondioxide, nitrogen, and methane. The gas diffusivity in drilling muds and completion fluids can also be determined using the present analytical interpretation methods.
Gas Segregation During WAG Injection and the Importance of Parameter Scaling in Three-Phase Models
Authors: Hustad Odd Steve , Kløv Trygve , Lerdahl Thomas Rage , Berge Lars Inge , Stensen Jan Åge , Øren Pal-Eric 
Published: December 2007

Abstract
Saturation histories from simulations on a mesoscopic-scale heterogeneous model at immiscible and miscible conditions are compared with emphasis on gas segregation. Selected models for three-phase flow, and scaling of the end point saturations, relative permeabilities, and capillary pressures have been applied. The flow parameters of the facies were obtained from pore scale network modeling with input from North Sea sandstones. The simulation cases included water, gas, and water-alternating-gas (WAG) injection.
Gas injection at irreducible water saturation demonstrates stronger gas segregation as the pressure exceeds the minimum miscibility pressure (MMP). Gas segregation is not so evident at the mesoscopic scale during WAG injection. High water saturation in the set-planes hampers the vertical gas flow. A bank of high oil saturation forms in front of the advancing gas at miscible conditions. Oil segregates to the set-plane below and the water cycle that follows mobilizes the accumulated oil.
A Novel Mechanism for Improving Gas Conformance
Authors: Irani Cyrus A. , Hilliard J. S. , Cude S. A. 
Published: December 2007

Abstract
A novel method is presented for improving gas conformance during IOR operations. The process exploits the injected gas phase for carrying the diverting agent to the thief zone, and has the potential to provide a significant improvement over existing water based diverting technology. Laboratory studies and results of an exploratory field test are presented. Studies are underway to design and implement a significantly larger field test.
Optimizing Waterflood Performance by Utilizing Hot Water Injection in a High Paraffin Content Reservoir
Authors: Cassinat Joseph C. , Payette Matthew C. , Taylor David B. , Cimolai Mauro P. 
Published: December 2007

Abstract
The application of heated water injection in a conventional oil reservoir under secondary recovery has received sparse review in the literature. In general, such a scheme can be difficult to justify. This is often due to both the additional capitalization and fuel costs offsetting the potential advantages that can be practically achieved for the effects of the differential water temperature to that of the formation. However, under appropriate circumstances, hot water injection can provide a significant advantage for secondary recovery that may warrant further investigation.
As a case study, the Senex field of northern Alberta, Canada contains a 37°API crude with high paraffin content in a low permeability shelf carbonate. The oil is essentially saturated with paraffin at the reservoir temperature of 36 C. Paraffin precipitation within the reservoir porosity accounts for declining production rates, which have been commonly treated and temporarily reversed with an extended history of chemical and solvent squeezes.
Due to the northern latitude of the field, source water has been injected at ambient temperatures to within several degrees of the freezing point for up to 7 months of the year. The impact of this operation on injector and reservoir performance proved to be of concern after an injection well appraisal revealed an extended loss of injection capacity in the early startup of waterflooding operations. Subsequently, the thermal implications for the viscous forces to the reservoir dynamics in waterflooding were studied in a numerical simulator, which demonstrated this mechanism for recovery impairment. In addition, a qualitative assessment of the further thermal implications for deterioration of reservoir performance from paraffin deposition was established. In order to test and further validate the conclusions of this analysis, a pilot hot water injection scheme was initiated in April, 2001.
This paper will describe the aspects of planning, testing and modeling that were completed prior to the field implementation of this project. Preliminary field results are also presented.
Geologically Based Screening Criteria for Improved Oil Recovery Projects
Authors: Henson Richard , Todd Adrian , Corbett Patrick 
Published: December 2007

Abstract
The choice of an Improved Oil Recovery (IOR) process for use in a particular reservoir depends on several factors; the habitat of residual oil, the properties of the reservoir fluids, reservoir conditions and reservoir heterogeneity.
Reservoir heterogeneity exists at all scales, from the micro to the mega-scopic. Previous workers have studied the effects of micro and meso-scale heterogeneities on IOR processes in detail, as many processes are designed to act at those scales, but have ignored macro-scale heterogeneities such as facies variations. These can have a large effect on an IOR process; controlling the magnitude and nature of the connectivity between wells, compartmentalising the reservoir and influencing the balance of capillary, viscous and gravity forces.
A database of 499 IOR projects in clastic reservoirs was collated. The macro-scale heterogeneity present in each reservoir was categorised by depositional environment using the Tyler and Finley Heterogeneity Matrix. The results show that successful IOR projects using a particular process cluster at certain combinations of lateral and vertical heterogeneity.
To investigate the distributions, a quantitative method of evaluating macro-scale heterogeneity was devised. These Lateral and Vertical Heterogeneity Indices (LHI and VHI) provide a simple method of summarising and communicating geological information between different people and disciplines.
Reservoirs with known levels of LHI and VHI were modelled, in which various IOR processes were simulated. Over 350 simulations of steam, polymer and Water Alternating Gas (WAG) injection processes were run and used to identify the processes that worked best under different levels of heterogeneity, dip and net to gross. The results showed that the Heterogeneity Indices can be used to predict the effect of macro-scale reservoir heterogeneity on these three processes and that objective, geologically based screening criteria could be derived. Using these criteria, it is demonstrated that in the high cost and low well density environment of the North Sea, WAG injection is the most viable IOR process, as the efficiency of the process is relatively unaffected by macro-scale heterogeneity.