bluuebunny/crossref_metadata_2025 huggingface dataset:
A Compliance-based Approach to Well Integrity Management
Authors: Wallace Gary , Kiddie Neil , Kearns John , Robinson Peter
Published: September 2008

This paper describes a process for actively managing well integrity throughout the development life cycle with a particular focus on the production operations / well maintenance phase. Although developed in relation to ConocoPhillips UK North Sea development wells, most of the features of the process have application to all development well operations (both onshore & offshore) under any regulatory regime.

The original well integrity management process was developed in order to demonstrate compliance with the UK Offshore Installations & Wells (Design & Construction, etc) Regulations 1996 (DCR). Since that time the original process has continued to be modified to improve effectiveness & efficiency. As well as describing the current process, this paper also describes its development and how we see that the process might evolve in the future.

DCR regulations form a part of the UK ‘safety case’ regime. The ‘safety case’ regime places a strong focus on the development of site-specific performance standards; it also utilises the principles of independent examination & verification in order to demonstrate compliance. The process described in this paper represents a significant new contribution to the management of major accident hazards in well operations since it focuses on the use of performance standards and independent examination in order to ensure well integrity.
Application of Membrane Filtration Technologies to Drilling Wastes
Authors: Oluwaseun Olatubi , Burnett David , Roy Hann , Haut Rich
Published: September 2008

The Environmentally Friendly Drilling (EFD) program is taking a renewed look at dealing with the issue of waste management and re-use particularly with regards to produced water and water based drilling wastes, developing solutions that would possibly reduce the size of reserve pits needed in drilling operations and achieve significant waste volume reduction through the extraction of water from drilling wastes encouraging reuse of the extracted water in drilling operations and the concentration of suspended solids.

The EFD is investigating the use of membrane-filtration technologies in the aforementioned aim of waste volume reduction and water extraction from drilling wastes. The investigation involves processing actual drilling wastes using various membrane types and configurations in developing solutions to challenges facing membranes particularly fouling. We are investigating the ability of these membranes to effectively remove the suspended solids from waste streams and refine the waste to levels where they could be used in drilling operations or sent for further treatment such as desalination. Our aim is to develop a mobile treatment unit made of a suitable membrane system that could be deployed to drilling sites to be used as an onsite option aimed at recycle or re-use of water resources.

We are currently investigating in our laboratories various membrane-filtration technologies with water based oilfield wastes and coupling this with our prior development of field deployed technologies in developing a cost efficient membrane filtration system for field application. We show in this report how membranes have been used in the filtration of actual solids laden field supplied water based muds and a solids simulated laboratory water based mud, highlighting the compatibility of membrane systems with water based muds.

In light of the evolving stringent regulatory standards and in demonstrating good stewardship of the environment, the Oil and Gas industry is expected to be active in reducing the footprint of its various activities on the environment and in showing optimal use of resources. This approach to dealing with drilling wastes confers the two-fold advantage of optimal use of water resources through re-cycle and the reduction of the footprint of drilling operations well within reasonable economic costs by saving significant waste treatment, hauling and freshwater costs.
Case History Review of the Application of Pressure Transient Testing and Production Logging in Monitoring the Performance of the Mars Deepwater Gulf of Mexico Field
Authors: Weiland Jeffrey , Azari Mehdi , Fox Phil , Dorffer Daniel
Published: September 2008

Proper characterization of a producing well has significant impact on asset management. Production schedules from different wells and further infill drilling in a field depend on the effectiveness and the pattern of the production drive mechanism. Whether the reservoir displays partial aquifer influx or is waterflooded, the flow profile of produced/injected water as well as the reservoir pressure, permeability, fluid saturations, and formation compaction are useful to properly evaluate the overall sweep efficiency. This information is more crucial in a field with multi-layered reservoirs having different permeability, pressures, and structure. Data acquisition should be scheduled and compared to baseline data such as a baseline pulsed neutron capture, production, or compaction logs. There should also be plans to monitor specific wells over the life of the project to observe and optimize the reservoir performance, characterize the reservoir response, and in the case of waterflooded reservoirs monitor the performance of the waterflood. Multi-rate multi-zone production logging and pressure transient testing are two excellent methods to achieve these goals.
IMESAFR: A New Tool for Wellsite Explosives Safety Assessment
Authors: Leidel D. J.
Published: September 2008

Many industries have begun to utilize the tool of probabilistic risk assessment to quantify the risks of personnel fatality and injury from possible equipment failures, human error, or personal exposure to hazardous material. The U.S. Department of Defense Explosives Safety Board, (DDESB), recognized the need for a software package, (termed SAFER), that could quantify the risk to related and unrelated personnel as a result of operations involving ammunition items. Recently, the Institute of Makers of Explosives, (IME), completed a project to develop a new version of risk assessment software for the commercial explosives industry. This software package termed IMESAFR can be applied to perforating gun loading shops, wellsites and storage facilities to assess quantitatively, the risk to operating personnel and the public as a result of these types of operations.

Heretofore, the only tool available for siting commercial explosives operations was the American Table of Distances, (ATD), which is limited to establishing the distance of a specific explosive storage magazine or manufacturing building with respect to a limited number of inhabited buildings, public highways, passenger carrying railways and other explosive storage magazines. One underlying assumption in the ATD is that the tables are intended to be applied to "exposures in rural areas", rendering the distances that the ATD prescribe unsuitable for multiple exposed sites occupied by a large number of people. IMESAFR permits a more in-depth evaluation of the risk to include such factors as multiple exposed sites to the explosives operation, the amount of time persons are exposed to the explosive operation, the type of explosive, and the nature of explosive operation in process, which significantly affects the probability of fatality or injury as a result of an unplanned explosives event.

This paper describes the IMESAFR Software, and its development, in particular, describing examples where it can be applied to the upstream oil and gas industry.

Probabilistic risk assessment is a very powerful tool to assist planners in siting operations involving oilfield explosives and to inform the operator of expected risk levels in situations where separation distances may be limited.
Modeling of Inversion Point for Heavy Oil-Water Emulsion Systems
Authors: Ersoy G. , Yu M. , Sarica C.
Published: September 2008

As the world's demand for oil increases, more heavy oil reservoirs are being discovered, drilled and produced. However, heavy oil production brings new challenges. One of the challenges is the formation of emulsions. Emulsions can cause high pressure losses, resulting in transportation and pumping problems and separation. The inversion point, at which continuous and dispersed phases in an emulsion changes, needs to be studied to improve knowledge of heavy oil-water emulsions.

A new mathematical model was developed in this study using fundamental thermodynamics and conservation of mass laws to predict the inversion point of an emulsion system. Simulation results indicate that the properties of surfactant, emulsion droplet size and standard chemical potentials of the liquid phases play very important role in controlling the inversion point of an emulsion system. The model proposed in this paper can help predict inversion point of an emulsion system. Estimation of inversion point of emulsions helps improve the existing emulsion viscosity correlations and develop new models when necessary. The improved heavy oil-water emulsion viscosity models can be used in design and operation phases of heavy oil fields.
The Cliff Head Field Development—Flow Assurance and Production Chemistry Challenges in a Marginal Field Context
Authors: Daniel Simon , Roberts Jon
Published: September 2008

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

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

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

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

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

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

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

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

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

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

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

Gel 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.
Experimental Investigation of Oil Recovery From Siliceous Shale by CO2 Injection
Authors: Kovscek A. R. , Tang G. Q. , Vega B.
Published: September 2008

Enhanced oil recovery from fractured low permeability reservoir rock is challenging and while studied previously, significant challenges remain in improving the recovery factor. In many cases the reservoir has been pressure depleted and gas released from solution. In such cases, continuous gas pathways from fracture to the matrix may have been created aiding our ability to deliver gas to the matrix. Gas injection (i.e., CO2) then proceeds from immiscible to perhaps miscible conditions. The efficiency of gas transport to the low permeability matrix is limited by the presence of a gas phase in the matrix, injection pressure, and cocurrent or countercurrent flow conditions, among others.

This work presents the results of a series of experiments using low permeability (0.02 – 1.3 mD), medium porosity (30 – 40 %) siliceous shale reservoir core samples initially saturated with either: live oil, depleted to a pressure of 200-300 psi; or dead oil brought to near miscible conditions; followed by CO2 injection at pressures proceeding from immiscible to CO2 near miscible conditions. Two gas injection modes were used: CO2 flow across one face of the core (countercurrent flow) which intends to account for the diffusive transfer mechanism; and CO2 flow along the length of the core (cocurrent injection). The experimental setup was monitored using X-ray computed tomography that helped to visualize phase flow and distribution during the processes.

The incremental oil recovery caused by the immiscible CO2 injection ranged from 0-10% for countercurrent flow mode and from 18-25% for cocurrent flow mode, whereas for near miscible conditions the recovery was found to be 25% for the countercurrent flow mode and 10% for the cocurrent flow mode. Countercurrent recovery appears to be critically sensitive to the distribution of the gas phase near the fracture face. Oil recovery potential by CO2 injection into siliceous shale rock is challenged by low permeability, rock heterogeneities, distribution of oil within the rock matrix, but it is aided by the presence of continuous gas pathways that allow CO2 penetration into the matrix. Near miscible injection displays clear multiple contact miscibility; also countercurrent flow seems to exhibit a greater recovery under near miscible as compared to immiscible conditions.
Engineering and Geologic Characterization of Giant East Texas Oil Field: North and South Pilot Studies
Authors: Wang F. P , Ambrose W. A. , Hentz T. F. , Bonnaffé F. , Loucks R. G. , A John , G Katherine
Published: September 2008

East Texas oil field (ETOF), discovered on September 3, 1930, is the second-largest oil field discovered in the United States. It has produced 5.42 BSTB of 39° API oil from >31,000 wells from lower Woodbine sandstones. Estimates of original oil in place (OOIP) have ranged from 6.8 to 7.5 BSTB. Based on a midrange OOIP value of 7.0 BTSB, current recovery efficiency is 77%, which is the highest of any giant oil field in the world. Two areas of the field, one in the north and the other in the south, were selected in 2007 for study of the primary engineering, geological and operational factors controlling recovery; for describing the detailed reservoir architecture; and for developing strategies for future exploitation.

The Upper Cretaceous lower Woodbine Group in ETOF, ~150 ft thick in the western downdip area, is truncated by a pre-Austin Chalk unconformity to the east. The Woodbine is composed of stacked, NE-SW-trending fluvial-dominated deltaic deposits, with dip-elongate distributary-channel sandstones pinching out over short distances into delta-plain and interdistributary-bay siltstones and mudstones. High-quality fluvial- and distributary-channel sandstones with average porosity and permeability of 25.2% and 2,098 mD, respectively, are the major producing lithofacies. The fluvial-channel sandstones that dominate the northern pilot area are laterally and vertically more continuous than the delta-dominated facies of the southern pilot area.

ETOF, with an average of 4.2-acre well spacing, is one of the most densely drilled fields. Production is supported by a active downdip aquifer. Major operating strategies have been downdip water injection, plugback, deepening for untapped intervals, and waterflooding in areas with poor reservoir quality as well as aquifer support. Its high-recovery efficiency stems from its high reservoir quality, low residual oil, favorable stratigraphic dip, effective aquifer support, stable water movement controlled by production rates.

Of the estimated 1.58 BSTB of remaining oil, only 70 MMSTB is likely to be produced under current operating techniques. However, a fraction of 410 MMSTB of remaining mobile oil may be produced by depositional-trend-guided deepening and water injection. The remaining approximately 1.1 BSTB of residual oil will only be produced by enhanced oil recovery methods. Because the reservoir is shallow and reservoir pressure low, CO2 flooding would most likely be immiscible. In addition, with most wells >60 years old, well-bore leakage is an environmental factor that must be considered prior to CO2 injection.
New Flux Surveillance Approach for High Rate Wells
Authors: Tosic S. , Ehlig-Economides C. A. , Economides M. J. , Vincent M. C.
Published: September 2008

Wells in high permeability reservoirs requiring sand control are commonly completed either with a high permeability fracture (HPF) or a high rate water pack (HRWP). These prolific reservoirs are capable of delivering high production rates, but the downhole flow velocity becomes a limiting factor. The downhole velocity is one of the most important factors in completion failure. To determine a safe producing rate for prolific wells, the current best practice is to monitor flux to avoid completion failure due to screen erosion or destabilization of the annular pack. Flux is the flow velocity at a critical location in the completion: at the screen face to avoid screen erosion, or in the annular pack to avoid pack destabilization. The commonly applied method for mathematically estimating the flux from the mechanical skin relies on a number of parameters that cannot be uniquely quantified, including the proppant permeability, the proppant turbulence factor, and the fracture skin. The calculated flux is highly sensitive to these uncertain parameters. When the flux is overestimated, the well rate will be unnecessarily restricted. Underestimation of the flux risks completion failure.

Most practitioners assume values for uncertain parameters, calculate the flux, and back-calculate the number of flowing perforations. Sensitivity studies will show the potential pitfalls of this technique. Instead, this paper presents an alternative approach to determine the flux as the total flow rate divided by the flow area, which, in turn, can be related to the number of perforations effectively conducting fluid from the reservoir to the wellbore. For the HPF case, this means how many perforations connect the fracture to the wellbore, which is a function of the angle between the well trajectory and the far field plane of the hydraulic fracture. When the angle cannot be determined due to a lack of the necessary stress measurements or stress isotropy, the flux will be calculated based on the pressure drop across the perforation tunnels obtained from the mechanical skin. The method and its advantages over existing techniques will be demonstrated using field data from deepwater Gulf of Mexico (GOM) wells.
Measurement of Non-Wetting Phase Trapping in Sand Packs
Authors: Pentland Christopher H. , Al-Mansoori Saleh , Iglauer Stefan , Bijeljic Branko , Blunt Martin J.
Published: September 2008

We measure the trapped non-wetting phase saturation as a function of initial saturation in sand packs. The application of the work is for carbon dioxide (CO2) storage in aquifers, where capillary trapping is a rapid and effective mechanism to render the injected fluid immobile: the CO2 is injected into the formation followed by chase brine injection or natural groundwater flow that displaces and traps it. Current models to predict the amount of trapping are based on experiments in consolidated media; while CO2 is likely to be injected at depths greater than around 800 m to render it super-critical, it may be injected into formations that tend to have a higher porosity and permeability than deep oilfield rocks. We use analogue fluids – water and refined oil – at ambient conditions. The initial conditions are established by injecting oil into vertical or horizontal sand packs 1 m long at different flow rates and then allowing the oil to migrate due to buoyancy forces. The packs are then flooded with water. The columns are sliced and the residual saturation measured with great accuracy and sensitivity by gas chromatography. This method allows low saturations to be measured reliably. The trapped saturation initially rises linearly with initial saturation to a value of around 0.11, followed by a constant residual as the initial saturation increases further. This behavior is not predicted by the traditional Land (1968) model, but is physically consistent with poorly consolidated media where most of the larger pores can easily be invaded at relatively low saturation and there is, overall, relatively little trapping. The best match to our experimental data was achieved with the Aissaoui (1983) trapping model.
Current Status of Enhanced Recovery Techniques in the Fields of Russia
Authors: Shandrygin A. N. , Lutfullin A.
Published: September 2008

Russia is one of the main oil producing country in the world with very long history of the oil industry. In one's time in former Soviet Union a lot of attention was paid to oil recovery problems. Unfortunattelly the unfavorable economic climate of the late 1980-s and economic shocks during the period of well-known events in the country in 1990-s caused the rapidly decline of the number of new EOR projects. EOR technologies started to develop in direction of sweep efficiency improvement by cheap agents. Nevetheless by now the very intereresting EOR experience has been accumulated in the country. It is likely that EOR- produced oil in Russia has not already reached its peak level and that it will increase above the current production rates because of improvement of economic situation in the country on the one hand and increasing of mature fields on the other hand.

The paper presents an overview of EOR field experiences in former Soviet Union and Russia for the last 25 years, an analysis of recent efforts and discusses briefly on perspectives for conventional and new EOR methods. The main EOR experiences reviewed are chemical flooding (and flow diverting technologies in particular), gas injection, thermal recovery process, microbiological and unconventional EOR.
Correlation Between Microseismicity and Reservoir Dynamics in a Tectonically Active Area of Colombia
Authors: Osorio J. G. , Peñuela G. , Otálora O.
Published: September 2008

BP operates the Cusiana volatile oil field and the Cupiagua gas condensate field in the Andean Mountains foothills province of Colombia (Fig. 1.). In 1992, a permanent seismic network of ten surface stations was installed in Cusiana and Cupiagua to obtain data for seismic hazard models necessary for the design of field infrastructure. The network is now in its sixteenth year of continuous operation. Currently, an average of 1000 microseismic events per month is recorded. The resulting seismological dataset is of high quality covering a range of seismic magnitudes down to about 1.0 on the Ritcher scale.

Over time, the Cusiana-Cupiagua Seismic Network (CCSN) has been used for different purposes. During the past few years, it has become increasingly evident that the network and its data is an invaluable asset for evaluation of conditions relevant to production/injection operations within the reservoirs and adjacent areas.

From the reservoir characterization and production operation standpoints, microseismic monitoring (also known as passive seismic) has had two main applications in Cusiana and Cupiagua: (i) to identify production/injection induced high transmissibility pathways and their temporal variations, and (ii) to image the orientation, extension, complexity, and temporal growth of hydraulic fractures.

This paper is focused on the first of these applications: how microseismicity has been used as a surveillance tool to track movement of reservoir fluids away from the wellbore. A short description of the seismic network is provided. Then, the methodology for data interpretation is discussed. Finally, partial results are presented showing how microseismicity monitoring is being applied to: (i) assess transmissibility changes due to stress and pore pressure changes through time, (ii) identify potential reactivation of pre-existing weak planes, and (iii) calibrate numerical models to improve history matches.

Analysis of the data shows a strong correlation between reservoir dynamics and production induced microseismicity in Cusiana and Cupiagua Fields with great potential as a surveillance tool for improved reservoir characterization and management.
The Determination of Tested Drainage Area and Reservoir Characterisation From Entire Well-Test History By Deconvolution and Conventional Pressure-Transient Analysis Techniques
Authors: Du Kuifu
Published: September 2008

The classical formula for estimating radius of investigation (Rinv) is based on the radial flow equation, which in most practical cases does not correspond to the actual reservoir conditions. This work presents a generalization of calculating drainage area or radius to the entire well test history without any flow regime pre-requisites, which represents a significant improvement to the classical Rinv formula. The methodology is based on integration of two advanced techniques: a) conventional pressure transient analysis (PTA) based "shrinking-box" method and b) pressure-rate deconvolution algorithm. Five field examples are analysed in detail to illustrate practical applications of the methodology including the detailed procedures for computing the minimum tested areas under various reservoir geometries and establishing the noise tolerance (or uncertainty) levels for the two methods as well as how to select and fine-tune some key control parameters governing the outcome of the deconvolution algorithm. These field case studies demonstrate that both methods, if carefully used with the proposed procedures, can yield an equivalent Rinv value, thus a reliable and verifiable result, derived from the entire test history. They also show that the deconvolution technique can obtain more reservoir information from the same dataset than a single pressure buildup or drawdown period, resulting in enhanced reservoir characterization and reduced uncertainties of the interpretation.
Velocity Calibration for Microseismic Monitoring: Applying Smooth Layered Models With and Without Perforation Timing Measurements
Authors: Pei Donghong , Quirein John A. , Cornish Bruce E. , Ay Erkan , Zannoni Steve , Kessler Calvin , Pettitt Will
Published: September 2008

Theorectically, the perforation shot origin time T0 affects the accuracy of the inverted velocity structure, and therefore the accuracy of subsequent microseismic event locations. The origin time can be obtained from perforation timing measurements or estimated from the picked arrival times. In order to investigate the role of origin time in velocity calibration, we designed two inversion procedures. In procedure A, T0 is calculated during the Occam's inversion while T0 is set to its true value in procedure B. A grid search locator is applied on both inverted models to produce two locations. We constructed three synthetic P-wave velocity models and add normally distributed random noise to the synthetic arrival times of all models. The noisy synthetic data are piped through procedure A to obtain location A and through procedure B to produce location B. Graphical analysis show that location A is closer to the true shot location than location B although both are close to each other. If we remove the data noise and repeat the test, location B is closer to the true shot than location A. It was observed that the inverted location A is better in terms of the distance from the true location if using noisy data and location B is better if using noise-free data. This indicates that uncertainties due to data noise cause our inconsistent observation and implies that perforation timing measurements are not necessary and may actually result in a less accurate velocity model.