bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Cliff Head Field Development—Flow Assurance and Production Chemistry Challenges in a Marginal Field Context
Authors: Daniel Simon , Roberts Jon 
Published: September 2008

Abstract
The Cliff Head Field, offshore Western Australia faced significant development challenges due to the field location and reservoir fluid properties. The influence of these challenges is apparent in the development solution adopted from sand-face to market. The modest reserve size required the application of a number of firsts, including multiple, innovative, new technologies in artificial lift, completion systems, CT (Coiled Tubing) deployed ESPs (Electric Submersible Pumps) combined with intelligent completion technology, a novel water "spike" approach to waxy crude transportation, a distributed chemical injection system, a remote controlled, not normally manned production platform, produced water re-injection and "hydrofrac" water-injection capacity. The application of these processes and technologies is described and the production history to date establishes the field as economic despite the challenges of a location away from existing oil field infrastructure and in an environmentally sensitive fishing area.
This paper describes the Flow Assurance and production chemistry challenges facing the development and the resulting Cliff Head development solution and production history to date.
Sand on Demand: An Approach to Improving Productivity in Horizontal Wells Under Heavy Oil Primary Production
Authors: Meza-Dìaz Brìgida , Sawatzky Ronald , Kuru Ergun , Oldakowski Kaz 
Published: September 2008

Abstract
The cold production recovery process, as it is practiced in Western Canada, is successful for vertical wells. Applications of cold production technology with aggressive sand production in horizontal wells, however, have been much less successful.
This paper presents the results of experiments performed to assess the feasibility of applying cold heavy oil production with horizontal wells using less aggressive (i.e., controlled) sand production strategies. Specifically, the effects of slot size, confining stress, fluid velocity and sand grain sorting on sand production have been investigated.
Preliminary results indicate that slot size selection is critical for establishing "sand on demand". For proper slot size selection, it is essential to know the grain size distribution of the sand; in particular, attributes such as the size of the coarsest fraction of the sand and the sorting (uniformity coefficient) of the sand. For example, it was observed in the sand production experiments that the critical pressure gradient for maintaining continuous sand production is much lower for well sorted sands than for poorly sorted sands. Ultimately, poorly sorted sands may require different criteria than well sorted sands for slot size selection.
Flow rates are also crucial for managing sand production since a critical pressure gradient is required for initiating sand production and maintaining continuous sand production. The critical pressure gradient decreases as the slot width or confining pressure increases. Large permeability increases were observed in the sand production region. Persistent sand production led to the growth of a channel and/or the presence of a dilated zone which had an elliptic shape.
New Carrier Method for Propellants Offers Flexibility, Simplicity, and Performance
Authors: Hale J. , Quattlebaum C. C. , Haney J. 
Published: September 2008

Abstract
Propellant-based well stimulation is an accepted technology in the oil industry; a number of papers have been published regarding its advantages and advancements (Folse et al. 2001; Gilliat et al. 1999; Yang et al. 1992). The additions of propellant stimulation modeling software and high-speed pressure recorders have greatly assisted in the development and maturing of the technology (Schatz et al. 1999).
The most commonly used propellant for near wellbore stimulation is the propellant sleeve. Propellant sleeve is simply a hollow tube of propellant that is positioned outside of a standard perforating gun and held into place by retaining rings. The detonation of the perforating charges ignites the propellant. The internal ballistic train of the perforating gun is not affected by the propellant because of the sleeve's external placement. This system is both reliable and effective.
A second and less frequently used technique places the propellant inside a vented hollow steel carrier, allowing propellant stimulation without the need of introducing new perforations. Unlike the propellant sleeve system, this system uses detonating cord to ignite the propellant. This method has the ability to stimulate virtually an unlimited amount of borehole by simply interconnecting the vented propellant carriers. However, the ballistic train is exposed to wellbore fluids and pressures. Therefore, when deploying longer intervals (greater than 7 m), the propellant system must be able to reliably continue the ballistics train between interconnected propellant carriers. In the past, the wet-connect system used was unreliable and limited the system to low wellbore pressure applications. Consequently, this method has struggled to gain acceptance primarily due to a lack of a reliable ignition system combined with limited stimulation pressure data.
This paper discusses a new propellant stimulation system that addresses reliability issues that have plagued propellant stimulation systems in the past. It also offers case studies that demonstrate the effectiveness of the new system, performance of the optimized propellant formula as well as the value created from the system's performance and flexibility.
Approaches to Managing Tight-Margin Drilling in Equatorial Guinea
Authors: Meeks William R. , Browning Greg M. 
Published: September 2008

Abstract
This paper discusses the work process and techniques used by the operator in Equatorial Guinea to manage drilling operations within a very narrow operating window between formation fracture and wellbore collapse. The operator's use of Fracture Closure Stress (FCS) treatments to expand the window by building integrity in over 1,000 ft of hole is also discussed.
In Equatorial Guinea, field maturity has led to some areas of lower reservoir pressure. These areas of lower reservoir pressure reduce wellbore integrity creating a tight drilling margin situation. The mud density and circulating pressure must be managed to prevent both lost returns and wellbore collapse. It was essential that these competing priorities be balanced effectively in order to successfully drill and complete field development wells.
The combination of depositional environment, lower reservoir pressure, and weak shale has significantly increased drilling complexity and uncertainty. While complexity can be addressed with rigorous engineering, management of uncertainty is more difficult requiring both enhanced design and surveillance techniques, as well as, rig-site workflow to ensure that data is analyzed and the correct decisions are made based on real-time observations.
This paper will benefit those planning and drilling tight drilling margin wells worldwide and provide work processes that will improve both team effectiveness and the chance of success.
Measurement of Gel Cleanup in a Propped Fracture With Dynamic Fracture Conductivity Experiments
Authors: Marpaung F. , Chen F. , Pongthunya P. , Zhu D. , Hill A. D. 
Published: September 2008

Abstract
The effect of residual fracture fluid gels on the conductivity of propped fractures has commonly been measured in the laboratory with a static fracture conductivity procedure in which a certain amount of proppant is placed in a fracture conductivity cell, and then fracture fluid is injected into the cell. This test does not capture all of the physics of the process of proppant placement and fracture closure as it occurs in an actual fracturing treatment. In particular, the interactions among the transport of fracture fluid down the fracture and leakoff into the formation can result in a completely different distribution of residual polymer in the proppant pack in the real fracturing process compared with the static conductivity test.
To more closely simulate actual fracturing conditions, we have developed a dynamic fracture conductivity procedure. In these experiments, fracture fluid/proppant slurry is injected into a fracture conductivity cell at injection rates representative of conditions in an actual fracture. Leakoff conditions are also set to mimic actual field rates. To be able to control leakoff at realistic rates, we use 3-inch thick core samples in the conductivity cell, rather than the 1/4 to 1/2 inch thick samples used in a standard API conductivity cell. After flowing the fracturing fluid slurry for some length of time, the cell is shut in, the fracture is closed by applying stress with a load frame, and then gas is flowed through the cell to represent the flowback period. During the gas flowback period, we repeatedly measure fracture conductivity to determine the amount of gel cleanup occurring.
We have conducted a series of dynamic fracture conductivity experiments using a crosslinked guar-based fracture fluid at 150 °F. One of the most significant findings is that the fracture conductivity measured with the same proppant loading using the static conductivity procedure is about twice as high as that obtained with a dynamic test. We also show how gel cleanup depends strongly on the gas flux through the fracture, on the presence of breaker, and on the polymer loading.
Multi-Year Scale Inhibition from a Solid Inhibitor Applied during Stimulation
Authors: Gupta D. V. Satya , Brown J. Mike , Szymczak Steve 
Published: September 2008

Abstract
Multi-year scale inhibition is the desired outcome from placing a scale inhibitor composite in a formation during the fracturing process. Traditionally liquid inhibitors applied through a squeeze have provided inhibition for up to one year. Deepwater operators, especially, desire longer inhibition periods. This paper reports on the twenty-four wells that have been treated for at least sixteen months. It also details the inhibition for two deep water wells that have been on line for about one year. At the time of the publication of the paper over five hundred wells have been treated with the solid inhibitor. The longest documented treatment has been in the ground for over three years.
Placing a scale inhibitor composite into the formation via the fracturing process requires a product that is compatible with the fracturing fluid, does not adversely affect the conductivity of the proppant pack and provides multi-year inhibition through the controlled release of the inhibitor into the produced water. The solid inhibitor is added to the fracturing proppant. Primarily this is a mass-balance process by which a finite amount of inhibitor desorbs over time. The goal is to maximize the inhibitor loading without negatively impacting the stimulation effectiveness.
Mineral scale deposition in the treated wells has not occurred in the time since the initial stimulation and inhibitor placement. In all wells, but especially for deep water wells where subsequent intervention represents a significant cost, this technology has financial benefit compared to traditional treatments. All treated wells continue to show scale mitigation, as measured by inhibitor residual in the produced water.
Mineral scale deposition in wells means costly well remediation. This means decreased production and workover costs. It has an adverse impact on lifting costs. This chemical technology advancement extends the period between remedial workovers well beyond traditional expectations. It will save operators money and may encourage the development of fields that might otherwise be viewed unprofitable or marginal.
Successful Pipeline Clean Out—Lessons Learned From Cleaning Paraffin Blockage From a Deepwater Pipeline
Authors: Poole Gary , Brock Gene , Szymczak Steve , Casey Greg 
Published: September 2008

Abstract
This paper presents a case history of inspecting, cleaning and re-establishing communication in a deepwater pipeline that had plugged because of paraffin deposition over an extended period. Early mitigation attempts did not remove the solid mass causing the blockage but, rather, compounded the problem.
A chemical capable of dispersing the wax mass was applied to the plugged pipeline through a snubbing unit. Access to the pipeline and the wax plug was gained by disconnecting the line at the subsea site, lifting the pipeline to a work rig, installing the snubbing unit and applying the chemical solution in sea water at a prescribed dilution ratio.
One critical step in dispersing and removing the solid wax mass was selecting the dispersant package. In addition, after the correct chemistry was identified, its application required a complex operation. A snubbing unit inside the pipeline jetted the chemical dispersant and drilled through the wax mass. The dispersed fluid was then returned to the working rig where the paraffins were disposed. The operation was successful and the pipeline was placed back into production. However, it was complicated by the ocean floor topography: The deepwater environment adds a degree of difficulty that is not experienced in shelf waters or on land. The exercise taught several lessons, the most significant being that a slow and consistent effort is ideal. Once the mass is dispersed it is best to continuously remove this fluid. Stop-and-start operations allow the solubilized mass to re-solidify as the solvent drains away from the mass under static conditions.
Although operators would like for all operations to proceed according to plan, unforeseen and undesirable situations arise. In the case of a plugged pipeline, several causes need to be investigated in order to prevent future occurrences. Operators need to know that operational experience combined with application chemistry exists to help unplug a deepwater pipeline.
Uncertainty Assessment of SAGD Performance Using a Proxy Model Based on Butler's Theory
Authors: Walter J. , Vanegas P , Deutsch Clayton V. , Cunha Luciane B. 
Published: September 2008

Abstract
Steam Assisted Gravity Drainage (SAGD) is an efficient method for thermal recovery of bitumen from the vast reserves available worldwide and particularly from the oil sands in western Canada. Flow simulators are available for predicting SAGD performance and are used to support reservoir management decisions; however, the high computational time associated with the use of such complex flow simulation makes it impractical for all locations especially when reservoir uncertainty and variable operational parameters are included in the making decision process. The use of a simpler analytical model as a proxy for the reservoir simulator is shown to be a feasible alternative to flow simulation. A proxy model based on the Butler's SAGD theory is developed to predict the oil flow rate, cumulative oil production and cumulative steam injection profiles during both: the rising and spreading steam chamber periods for a confined SAGD well pair. Modifying factors are used to fit the proxy to flow simulation results to account for conformance and reservoir heterogeneity among other factors. A critical aspect of the proxy model is a realistic parameterization of geological heterogeneity. Monte Carlo Simulation (MCS) and the proxy model permit an efficient transfer of the uncertainty in reservoir and operational parameters through to performance variables such as oil production and steam oil ratio. An example application for a single well pair showed the efficiency of the methodology in terms of computation time. The results permit improved reservoir management of complex SAGD projects.
Design of Carbon Dioxide Storage in Oilfields
Authors: Qi Ran , LaForce Tara C. , Blunt Martin J. 
Published: September 2008

Abstract
We extend our study of the design of carbon dioxide, CO2, storage in aquifers (Qi et al., 2007) to oilfields. We demonstrate that pore-scale capillary trapping is an effective and rapid mechanism to render the CO2 immobile in oil reservoirs. We construct analytical solutions to the transport equations, accounting for relative permeability hysteresis. We use this to design an injection strategy where CO2 and brine are injected simultaneously followed by chase brine injection. We study field-scale oil production and CO2 storage using a streamline-based simulator that captures dissolution, dispersion, gravity and rate-limited reactions in three dimensions. While injecting at the optimum WAG ratio gives the fastest oil recovery, this allows CO2 to channel through the reservoir leading to rapid CO2 breakthrough and extensive recycling of the gas. We propose to inject more water than optimum. This allows to CO2 to remain in the reservoir, increases the field life and leads to improved storage of CO2 as a trapped phase. A short period of chase brine injection at the end of the process traps most of the remaining CO2.
Effect of System Pressure on Restart Conditions of Subsea Pipelines
Authors: Ekweribe Chiedozie , Civan Faruk , Lee Hyun Su , Singh Probjot 
Published: September 2008

Abstract
As the oil industry invests billions of dollars in oil and gas production from deep waters, the concern for flow assurance of reservoir fluids to the surface and their subsequent delivery to relevant markets becomes very critical to justifying project economics and meeting the ever growing demand for petroleum products. For various reasons, production systems could be shut down long enough to form waxy oil gels in subsea pipelines which can completely hinder further production. Hence, the need for a good understanding of the various phases of waxy crude transformation in a cold subsea pipeline and all factors affecting restart conditions cannot be over emphasized.
This paper provides a comprehensive review of the various studies done on wax crystallization, deposition and gelation as well as the yielding behavior of waxy crude gels during pipeline restart. The study focuses on detailed experimental investigation of temperature and pressure effects on gel strength. The influence of testing temperature on gelation kinetics was studied on a controlled stress rheometer (CSR) and analyzed using the modified phenomenological Avrami model for isothermal crystallization proposed by Lopes-da-Silva and Coutinho (2007). On the other hand, the effect of system pressure – a parameter widely neglected in pipeline restart studies, on restart conditions was studied on a novel model pipeline system which produced the best reproducibility of yield pressures reported so far in literature. The model pipeline results were further compared to yield point tests on a CSR. The results of the experimental work conducted in this study suggest that at higher shut-in pressures, weaker gels may be formed which facilitates pipeline restart.
Geosteering with a Combination of Extra Deep and Azimuthal Resistivity Tools
Authors: Meyer W. Hal , Hart Eric , Jensen Kaare 
Published: September 2008

Abstract
A resistivity tool with a large depth of investigation (greater than 30 meters in ideal conditions) has been designed and used in the North Sea Grane field for over three years. An azimuthal resistivity tool with a depth of detection of about 6 m in ideal conditions has now been added to the bottomhole assembly. When the deeper measurement detects a conductive zone there is no information about the direction to the target because the measurement has azimuthal symmetry. The shallower azimuthal measurement will be able to give the direction to the conductive zone when it comes within the depth of detection of the tool.
The target for this effort is a thick reservoir (about 60 meters) that has a long, gradual transition from a resistivity of about 300 ohmmeters at the top of the sand to the water zone of about 0.5 ohmmeters at the bottom. A shale formation of about 1.0 ohmmeter is found both above and below the sand. A deep resistivity tool, a normal propagation resistivity tool, and an azimuthal resistivity tool are all used to place the well in the ideal position to produce the reservoir.
The azimuthal tool has no response in a homogeneous formation. The result is a better depth of detection because the signal from the target zone does not have to be removed from a constant background signal. Unfortunately, a gradient is not a homogeneous formation and the result is a background response roughly 10 times the normal noise floor of the tool. However, the shallow measurements of the traditional axial propagation resistivity tool are used to estimate the response of the azimuthal tool to the resistivity gradient. The difference between the estimated response and the actual response is a better indication of a nearby conductive bed.
Both synthetic models and actual data are used to show how the combination of the three resistivity tools can geosteer in this complicated environment. In particular, this combination is able to distinguish between a shale body above the tool and a shale encroaching from below.
Modeling Particle Gel Propagation in Porous Media
Authors: Wu Yu-Shu , Bai Baojun 
Published: September 2008

AbstractGel treatments are a proven cost-effective method to reduce excess water production and improve sweep efficiency in waterflood reservoirs. A newer trend in gel treatments uses particle gel (PG) to overcome some distinct drawbacks inherent in in-situ gelation systems. In this paper, we present a conceptual numerical model, based on laboratory tests and analyses, to simulate PG propagation through porous rock. In particular, we use a continuum modeling approach to simulate PG movement and its impact on isothermal oil and water flow and displacement processes. In this conceptual model, the PG is treated as one additional "component" to the water phase. This simplified treatment is based on the following physical considerations: (1) PG is mobilized only within the aqueous phase by advection in reservoirs; (2) PG, once retained in the porous media, will occupy pore space in pore bodies or pore throats and therefore reduce the permeability to bypassing water or oil; and (3) PG mobilization may not occur through pores or pore throats until some thresholds in pressure and/or pressure gradients are achieved and these threshold conditions are described by analogy to non-Newtonian fluid or non-Darcy flow in porous media, i.e., by a modified Darcy's law. The model is able to predict and evaluate the effects of PG as a conformance control agent to improve oil production and control excess water production.