bluuebunny/crossref_metadata_2025 huggingface dataset:
Polymer-Free Fluids: A Case History of a Gas Reservoir Development Utilizing a High-Density, Viscous Gravel-Pack Fluid and Biopolymer-Free Reservoir Drilling Fluid
Authors: Campbell S. , Bye G. Kristvik , Morris L. , Knox D. , Svoboda C. , Tresco K. , Hurst G. , Parlar M.
Published: December 2007

This paper presents a case history of the completion procedures applied to a four-well gas reservoir development in the Norwegian sector of the North Sea where open-hole gravel packing was utilized as the sandface completion technique.

The chosen technique to gravel pack the wells was based upon Alternate Path Technology, which incorporates shunt tubes with nozzles on the outside of the gravel pack screen. These shunts create an alternative flow path, allowing slurry to bypass premature bridging and fill any voids beyond the bridge. The use of shunt tubes gives the opportunity of achieving a complete gravel pack without the requirement of a filtercake-sealed wellbore. This introduces the possibility for the filter cake to be removed during the packing operation. As a result, a low-solids drilling fluid that deposits a chemically degradable filter cake can be utilized.

The reservoir pressure in this field required relatively high-density, reservoir drilling and gravel pack fluids (1.65 SG / 13.75 lb/gal). This paper describes the design and development work involved in formulating a mutually compatible, calcium bromide-based reservoir drilling fluid and a Viscoelastic Surfactant (VES) based gravel pack fluid and the subsequent successful application in a subsea field development.
Improve the Economics of Oil and Gas Wells by Reducing the Risk of Cement Failure
Authors: Ravi K. , Bosma M. , Gastebled O.
Published: December 2007

One of the main objectives of a primary cement job is to prevent formation fluids from migrating into the annulus. To achieve this objective, the cement sheath should withstand the stresses induced by the various well operations and maintain integrity during the life of the well. However, the majority of the cement design programs in the industry today consider only the slurry properties and do not assess the effect of the mechanical properties of the cement sheath on the final well design.

A design procedure has been developed to estimate the risk of cement failure as a function of cement sheath and formation characteristics and well loading. A few examples of well loading are pressure testing, well completion operations, hydraulic fracturing, and hydrocarbon production. The design procedure is based on a finite element analysis and simulates the sequence of events from drilling through cement hydration, well completion, and production operations. The cement failure modes simulated are debonding, cracking, and plastic deformation.

The cement is assumed to behave linearly as long as its tensile strength or compressive shear strength are not exceeded. The material modeling adopted for the undamaged cement is a Hookean model bounded by smear cracking in tension and Mohr-Coulomb in the compressive shear. Shrinkage and expansion of the cement are included in the material model.

The need to design a fit-for-purpose cement sheath is accentuated by the sustained casing pressure observed on a number of wells after they were put on production and on some HPHT wells after the displacement fluid was changed over to a well-completion fluid. The pressure in the annulus side sometimes results in an inability to continue further operation. Applications are discussed and examples are provided. From the processes reviewed in this paper, one can estimate the risk of failure of various cement systems and select a fit-for-purpose system that will minimize the overall cost. This process should improve the economics of constructing and producing oil and gas wells (cost effective life cycle design) and also improve safety because zonal isolation failures may be reduced.
A New Approach to Anchoring a Semisubmersible in Deepwater Areas Subject to Tropical Revolving Storms
Authors: Springett CharlesN. , Soles Julian , Zimmerman Evan
Published: December 2007

GlobalSantaFe Corporation has entered into a contract with PPL Shipyard in Singapore to build two new semi-submersible drilling units. The design of these rigs is described in detail in a paper presented in Rio de Janeiro in October 2001 (Ref 1). Santa Fe's objective with these rigs is to satisfy a demand for high capacity drilling units to drill development wells in deep and ultra deep water in the moderate environment areas of the world such as West Africa, Brazil and the Gulf of Mexico. A significant number of Oil Company plans for such locations include a requirement that the unit be capable of attaching itself to a pre-laid mooring system rather than relying on dynamic positioning. This requirement presents a unique challenge to those units that will operate in the Gulf of Mexico. The Gulf of Mexico (and some parts of South East Asia) are subject to Tropical Revolving Storms (hurricanes) which place particular burdens on remote drilling operations.

Historically all rigs in the Gulf of Mexico, with the exception of dynamically positioned drill ships, have been secured and abandoned in the face of hurricanes. It may be that this policy must be rethought in light of the increased number of very large drilling units operating at the outer edges of the continental shelf up to 200 miles from land. Until that happens the policy is still to evacuate which means the mooring system must be adequate to keep the unit on location even if the hurricane passes right over it.
PC-Based System Optimizes and Increases Bit ROP
Authors: Pinckard Mitchell D. , Proehl Tom
Published: December 2007

This case-history paper shows how use of a personal computer (PC)-based sensing, calculation, and display drilling enhancement system (DES) allows drillers to take advantage of years of knowledge accumulated by their predecessors to accurately control weight on bit (WOB) and rate of penetration (ROP) in land-based and offshore drilling operations. Use of the system in more than 100 wells over a 2-year period has resulted in approximately 20% improvement in ROP. Significantly, the drillers achieving this record represented various drilling contractors, cultures, disciplines, and experience levels.

At the heart of the system is statistical process software that analyzes and optimizes WOB and ROP by showing the driller two graphical lines. One line shows what WOB should be (target WOB) and one line shows the actual WOB. The driller manipulates the rig brake to match the actual WOB with the target WOB (a process known as "stitching the line"). Traditional training methods required the driller to learn to "feel" the rig vibrations and sense other signals to attempt to optimize penetration. Gaining the skill to be an efficient driller naturally required a great deal of time and potentially great expense in bit damage and excessive rig time.

A second set of displays available at the rig enables the company man to monitor WOB and ROP from the doghouse. The software samples data often enough to mathematically forecast optimum WOB in real time for any operating condition. A digital recorder system furnishes input to the DES and feeds data to an analytical tool that gives drillers and company men a method of recognizing trends and anticipating coming events. Lessons learned from each job are archived to be used as input to company training.

The paper presents operational details, illustrations, lessons learned, and case histories that show the utility of automated WOB/ROP control and trends analysis as dual means of "managing the challenges of a cyclic industry."
Gas-Influx Events in a Deep Water Exploratory Well: A Field Case History
Authors: Lage Antonio C. V. M. , Silva Paulo R. C. , Gonçalves Clemente J. C. , Borges Francisco A. T. , Mansano Renato B. , Imanishi Roberto M. , Martins Francisco S. B.
Published: December 2007

Several gas-influx events have occurred during drilling ESS-107, an exploratory well in a 1286 m of water depth offshore location in the southeast coast of Brazil, state of Espírito Santo.

The 9 ⅝" casing was set at 3804 m for drilling the final 8 ½" phase of the program. Then, a sequence of gas-influx events affected substantially the overall performance of the drilling activity. The first influx occurrence was observed while drilling at 4719 m and it was initially diagnosed as over-pressured. Consequently, after using the driller's method to remove the gas, the mud weight was increased from 11.3 to 12.5 lbm/gal. After that, some other well control incidents happened in sequence while drilling from 4719 to 4826 m. Despite the suspicion of a fracture breathing formation phenomenon, the mud weight was increased up to 13.7 lbm/gal without putting an end to the flow of gas into the well. In addition, as water based mud (WBM) was routinely flowing through the choke and kill lines mixed with gas, the low temperature of the environment close to the seafloor triggered the formation of hydrate. So, both kill and choke lines were plugged, which was indeed the first occurrence of hydrate formation in deep water while drilling in Brazil.

The present study analyzes the influxes based on all available data, such as daily drilling reports, daily drilling fluid reports, final well report, mud logging data, pressure while drilling (PWD) data, etc, to determine if the fracture breathing formation phenomenon was really the driven mechanism. The control procedures used are also discussed and evaluated. Finally, a proposal is presented to improve the overall drilling performance for the succeeding wells in the area.
New Hard Rock Roller Cone Bit Technology/Operational Excellence Improves Economics in Mature East Texas Gas Fields
Authors: Martin Donnie , Jacobsen Jim
Published: December 2007

Because of increased demand for natural gas in the United States, the mature East Texas province is experiencing a surge in drilling activity. However, due to marginal economics of these fields, it is critical to keep drilling costs at a minimum. A typical well in this region must penetrate several sand, shale, and carbonate formations as well as the highly abrasive Travis Peak and Cotton Valley formations before reaching the reservoir target. The Travis Peak is normally topped around 6050-6400 ft, followed by the Cotton Valley at approximately 8000 – 8400 ft. Each of these formations is about 1200-1700 ft thick. Traditionally, extremely abrasive sections in these formations have severely limited the life of IADC Class 647 through 817 roller cone bits. Because of severe gauge and cutting structure wear, the bits run previously were normally pulled after drilling about 800 ft. The shortened life meant three to five bits were required to complete the two intervals.

The authors will also discuss the application and development of a new hard rock (HR) bit that is drilling up to 20% more footage than the IADC 647 and 817 types run previously. The new IADC Class 647 and 817 roller cone bits incorporate new cutting structure geometry and enhanced gauge protection along with metallurgical improvements. Today, the Travis Peak and Cotton Valley formations are being drilled with three to four bits averaging more than 1000 ft per bit. The authors will present case studies of typical Travis Peak and Cotton Valley wells in East Texas documenting significant performance improvement and reduced cost per foot.

The operator has also improved operational efficiency (incident-free) reaching bottom hole objectives quickly reducing open-hole exposure and costly "flat" time. The authors will discuss changes that allowed a specific operation to reach the target formation in record time, breaking a long-standing field record.
Seismic Measurement While Drilling in Azerbaijan and Brazil
Authors: Harrold T. , Poole A. , Nelson L. , Hawthorn A. , Underhill W.
Published: December 2007

This paper presents field results obtained while drilling difficult offshore wells in Azerbaijan and Brazil using a new service that delivers conventional check-shot data while drilling. The operation is similar to a conventional wireline operation in that it uses a surface-deployed source and downhole receiver. The key difference between this service and wireline seismic services is that the receiver is included in the drilling assembly; therefore, drilling does not have to be stopped to take measurements. The first case study presents results from the A-1 deviated wildcat well in the South Caspian Sea, where the service was used to reduce depth uncertainty while drilling. The tool delivered real-time check-shot data that were accurate to within 3 ms of a conventional vertical seismic profile (VSP) over the same interval (equivalent to a 10-m depth error at a 4-km depth). In the second case study, seismic data from the B-2 well in Brazil were used to set casing in a narrow window between a fault and the primary reservoir target. The data enabled safe and successful installation of the casing. Both operations were completed with zero rig downtime. Data accuracy was suitable for real-time decisions and eliminated the need to stop drilling to run intermediate wireline VSP surveys. The service offers the industry new options for reducing uncertainty in the well construction process, and it can therefore make a significant impact on cost and safety while drilling a well.
Water-Based Alternatives to Oil-Based Muds: Do They Actually Exist?
Authors: Bland R. G. , Waughman R. R. , Tomkins P. G. , Halliday W. S. , Pessier R. C. , Isbell M. R.
Published: December 2007

Water-based mud designs as alternatives to oil-based or synthetic-based muds are compared versus history of use. Water-soluble designs and water-insoluble designs are discussed as well as a combination approach used by Woodside Energy to drill on the Northwest Shelf, Offshore Australia. Perfornance of a water-based 2-phase polyglycol mud system containing a Drilling Enhancer with an appropriate bit design was technically and economically equivalent to that with a synthetic-based mud.
Polyurethane Grouting Geothermal Lost Circulation Zones
Authors: Mansure A. J.
Published: December 2007

Polyurethane grouting has been successfully applied to a lost circulation zone in a geothermal well at Rye Patch, NV. Previously, failure to seal this zone resulted in the temporary abandonment of the well after twenty cement plugs, including 15 conventional, two thixotropic, and three with foam cement, were unsuccessful. Advantages of polyurethane grout are that the viscosity and setting time can be controlled to fit the job. The grout can be engineered to have a low viscosity while being pumped and then gain strength in a short period, minimizing "waiting-on-cement" and the potential for the plug to be washed out. Polyurethane has been successfully used in core drilling operations (slim holes) to stop lost circulation and stabilize boreholes; however, previous attempts to apply polyurethane grouting to large diameter geothermal boreholes have not been successful. The techniques applied to grouting with polyurethane at Rye Patch were adapted from civil engineering technology where polyurethane is becoming the grout of choice for sealing high cross flows. The success of the grouting of the loss zone at Rye Patch was a result of packing off the hole and squeezing the grout, using sufficient polyurethane to sweep away the drilling mud, and controlling the gel time.
Membrane Efficiency in Shale - An Empirical Evaluation of Drilling Fluid Chemistries and Implications for Fluid Design
Authors: Schlemmer R. , Friedheim J. E. , Growcock F. B. , Bloys J. B. , Headley J. A. , Polnaszek S. C.
Published: December 2007

This paper describes continuing efforts to develop a water-based drilling fluid that will provide the osmotic membrane behavior and wellbore stability of an oil-based drilling fluid. A pore-pressure-transmission technique in use for several years as a tool to measure osmotic behavior has been refined for improved measurement of changes in shale permeability and pore pressure in response to fluids interactions with outcrop and preserved shale specimens. Conventional invert emulsion and water-based drilling fluids containing selected additives have been tested in this ongoing study. The data have been used to achieve an understanding of what might be called "membrane efficiency" and how that concept may relate to shale stability.

Laboratory measurements of differential pressure development and calculation of "membrane efficiency" for invert emulsion fluids have produced surprising results. Data have been collected that supports the notion that invert emulsion drilling fluids do not necessarily yield a perfect osmotic membrane. The nature of the solute in the internal phase, not just its concentration and resultant water activity, and the emulsifier package may affect the interaction of invert emulsion fluids with shales, including the transport of fluids into or out of the shale.

Observed osmotic pressure differences are compared with values predicted by osmotic theory. From this comparison arises an easy-to-understand empirical concept of membrane efficiency. The assumption that specification of a solute and its concentration in the internal phase of an invert emulsion fluid is sufficient for assuring generation of an effective drilling fluid may be incorrect.

Preliminary results are given for water-based mud formulations which achieve about ¼ to ½ the osmotic pressure of a typical oil-based mud.
Casing Deformation in a Tectonic Setting: Evaluation, Impact and Management
Authors: Last Nigel , Mujica Santiago , Pattillo Phillip , Kelso Gary
Published: December 2007

Ovalisation of casing strings has been detected in the tectonically active foothills of Colombia South America, initially through operational difficulties, and subsequently by extensive monitoring.

Characterising the deformation, assessing its impact on well integrity, and developing a strategy for managing the consequences to achieve improved business and operational decision making are summarized in this paper.
Extending Squeeze Lifetimes Using Miscible Displacement
Authors: Collins I. R. , Hewartson J. A.
Published: December 2007

As the industry moves towards increasing deepwater production, the very high cost of well intervention places large constraints upon the performance of scale control options. In particular, where scale is managed by squeeze treating, it is an absolute requirement that the treatment lasts as long as possible and efficiently utilizes the applied chemical. This paper discusses using enhanced oil recovery-type surfactant systems in conjunction with scale inhibitors to dramatically extend the squeeze treatment lifetime. It is believed that the treatment lifetime is extended by the miscible displacement of organic material from formation surfaces thereby increasing the surface area available for the scale inhibitor to adsorb onto. The efficacy of this approach, using simple to formulate packages, is demonstrated by coreflood data in which the lifetime of the treatment is extended by up to four times.
A New Model for Mineral Scale Adhesion
Authors: Collins I. R.
Published: December 2007

Mineral scale formation and deposition on downhole and surface equipment is a major source of cost and reduced production to the oil industry. One potential means of preventing losses due to scale is to prevent it adhering/depositing on key components in the production system (such as downhole safety valves and key parts of intelligent well systems). In general, the coatings proposed to prevent deposition of scales are made of low-surface energy materials. However, industry experience of non-adherent coatings is not good and a search of the literature suggests that there are a number of contrary reports on the effects of surface energy on solid deposition behavior. Some reports show that deposits attached preferentially to high surface energy surfaces, while others purport to show that deposits attach preferentially to surfaces with low surface energy. Numerous studies also indicate that there is little relationship between surface energy/wettability and deposition behavior. Obviously a sound theoretical explanation of the observed deposition behaviour on various surfaces is crucial for the development, and deployment, of low-deposition surfaces. In this paper, the extended DLVO theory is used to explain scale deposition behaviour on metal substrates, and on modified metal surfaces. The proposed theory is shown to agree well with the limited experimental data available and thus provides the basis for a sound theoretical approach to controlling and preventing scale adhesion on surfaces
Development and Application of a Silicate Scale Inhibitor for ASP Flooding Production Scale
Authors: Qing Jia , Bin Zhou , Ronglan Zhang , Zhongxi Chen , Yuchun Zhou
Published: December 2007

Three ASP (Alkaline, surfactant and polymer) flooding projects and one multicomponent foam flooding project have been carried out in Daqing Oilfield. The increases of oil recovery rates are all above 20% (OOIP). One of the major troubles that happened during the three ASP flooding projects and the multicomponent foam flooding project was silicate scale deposition in the tubings of production wells which caused frequent downhole operation failure. To prevent scale deposition in production wells, a scale inhibitor, which works well in brines of pH values as high as 12 was developed. The scale inhibitor is effective both on carbonate scale and on the mixed scale of carbonate and silicate. The scale inhibitor was tested on 6 production wells in two ASP flooding project zones. The pull-out period of the tested production wells were elongated from 1 month to 9 month during the test.
Modelling of In-Situ Scale Deposition: The Impact of Reservoir and Well Geometries and Kinetic Reaction Rates
Authors: Mackay E. J.
Published: December 2007

Previous work has demonstrated how and where the mixing of incompatible brines occurs in waterflooded reservoirs, and what the impact would be on scale prevention strategies in terms of timing and placement of squeeze treatments. This paper extends this work, by modelling the resulting in-situ deposition process. The location of maximum scale deposition and the resulting brine compositions at the production well are calculated for a range of sensitivities, including reservoir geometry (1D, 2D areal, 2D vertical, 3D), well geometry (location and orientation within field and with respect to other wells and the aquifer), and reaction rate (ranging from no precipitation to equilibrium).

In conventional systems with no aquifer, it is demonstrated that maximum scale deposition occurs in the immediate vicinity of the production wellbore, and therefore low produced cation concentrations indicate inadequate squeeze treatments. In systems where water injection is into the aquifer, low cation concentrations may also result from deposition deeper within the reservoir. Maximum scale dropout still occurs as the fluids approach the production well, but sufficiently far from the wellbore to be unaffected by squeeze treatments, or to have any major impact on productivity. The reaction rate is critical in determining the amount of scale deposition, but even under equilibrium conditions, sufficient concentrations of scaling ions are delivered to the production well to necessitate squeezing the well, although using lower volumes of inhibitor. Once cation concentrations have been reduced, it is predicted that they will never pick up again.

This paper also discusses some of the limitations of modelling such systems, which include the determination of the kinetic reaction rates, size of the mixing zone, and the impact on permeability. Although the thermodynamics are fairly well understood, the kinetics are much more difficult. The size of the mixing zone is affected by numerical dispersion, and computationally intensive techniques are required to overcome this problem. Previous experience shows that formation damage factors are very difficult to extrapolate from coreflood data because there is a great difference between the dimensions of the mixing zone in the reservoir and the core plug.
Managing Workplace Health and Welfare-related Issues in the Shadows of HIV/AIDS: The Way Forward in the Oil and Gas Industries
Authors: Faleyimu B. xsL. , Ajayi PA , Fagade O. A. , IH Jonathan , Kpiasi E. O.
Published: December 2007

HIV/AIDS has become an unprecedented epidemic and public health emergency. Globally, about 36 million people are infected with HIV, and over 21 million have died of AIDS-related illnesses and the number of new HIV infections continues to rise. In some countries in Africa, AIDS-related morbidity and mortality are causing major reversals in development, childhood mortality, and survival and life expectancy.

HIV/AIDS presents a major obstacle to economic growth and stability in the workforce and the epidemic has affected most business with prolonged staff illness, absenteeism and death, thereby impacting on productivity, employee benefits, occupational health and safety, production costs and workplace morale.

Both private and public sectors now have strong economic and social reasons for becoming active in promoting HIV/AIDS prevention both in the workplace and in the community if they are to protect the "bottom-line".

In pursuing this obligation, one area of controversy is Pre-Employment and Workplace HIV testing as it affects job placement, disengagement, employee benefits and co-workers fears. The AIDS epidemic has introduced a potentially complex conflict between the doctrine of strict confidentiality, beliefs of human right activists, employee's future and the dictates of business interest, with serious ramification for the individual, the family, employers and the community.

As the HIV/AIDS epidemic progresses, companies continue to face increasing numbers of HIV-positive employees and will have to deal with a variety of employee-related health and benefit issues.

One of the most effective ways of reducing and managing the impact of HIV/AIDS in the workplace is through the implementation of an HIV/AIDS Workplace policy and Prevention programs. This paper will therefore attempt to review HIV/AIDS in the Workplace, the Health and Welfare-related issues especially as it affects the Oil and Gas Industries and drawing from the experience of the Chevron's Workplace AIDS Prevention program, proffer a way forward.
Flow Behavior of Fracturing Slurries in Coiled Tubing
Authors: Shah S. N. , Zhou Y. , Goel Naval
Published: December 2007

Hydraulic fracturing through coiled tubing (CT) has become an effective and economical stimulation technique for wells with multiple zones to be fractured. Yet, prediction of friction pressure losses of fracturing slurries in coiled tubing presents a unique challenge in the fracturing job design.

This paper presents an experimental study of friction pressure losses of fracturing slurries in coiled tubing using a full-scale coiled tubing test loop which consists of 1000 ft 2–3/8″ coiled tubing and 200 ft 2–3/8″ straight tubing sections. The fracturing slurries were prepared with guar-based gels at various polymer and sand concentrations. Based on the experimental results, the characteristics of the flow behavior of fracturing slurries as affected by sand concentration, base gel rheology and centrifugal forces are discussed. A new correlation has been developed and can be used to predict the friction loss increase over base gel friction.

The coiled tubing erosion mechanisms (sliding abrasion, random particle impact, and directional particle impact) have been discussed. The abrasion by sliding sand bed is believed to be the dominant erosion mechanism.
Practical Application Of Spherical Flow Transient Analysis
Authors: Abbott W.A. , Collins T. , Tippie D.B.
Published: December 2007

Introduction

Spherical flow is not a new concept, and its occurrence has long been recognized. Muskat derived equations for the steady-state fluid velocity, potential function and productivity for wells producing from partially penetrated strata. Transient spherical flow theory has been described by Chatas, Culham and others. This paper attempts to demonstrate the practical uses for spherical flow analysis based practical uses for spherical flow analysis based on the theory developed by others. Examples of field data are used to demonstrate how this analysis can aid in well test interpretation and provide data and insight for reservoir and provide data and insight for reservoir and production studies. production studies. CONDITIONS CREATING SPHERICAL FLOW Ideally spherical flow is flow along the radii of a sphere. Concentric spheres are equipotential surfaces. The center of the sphere is either a point sink or point source. Figure 1 shows the ideal geometry of spherical flow. Hemispherical flow, also shown in Figure 1 is identical to spherical flow with the obvious exception that the flow is contained within a hemisphere. Analysis is the same for spherical and hemispherical flow, The term "spherical flow" will be used herein and is meant to include hemispherical flow. Spherical flow is created -in petroleum production when massive reservoirs are partially production when massive reservoirs are partially completed or partially penetrated. Figure 2 shows these two conditions. For these two cases, the flow is not purely spherical because the completion interval is not a true point sink. However, the flow is spherical in a practical sense if the completion interval is very short relative to the net pay. It can be seen from these Figures that any condition forcing flow toward a single "sink" will promote spherical flow. Data obtained from a wireline tester are analyzed using spherical techniques. Plugged perforations or blockage of a large part of an open-hole interval may also promote spherical flow. promote spherical flow.
Miscible Gas Injection in Fractured Reservoirs
Authors: Uleberg Knut , Høier Lars
Published: December 2007

This paper discusses miscible gas injection in fractured reservoirs, based on compositional reservoir modeling. Developed miscibility in conventional one-dimensional systems is dependent on fluid properties alone, and can be estimated by well known experimental and numerical procedures. This is not the case for heterogeneous and multi-dimensional systems such as fractured reservoirs.

Based on a multi-cell algorithm a method is proposed to determine conditions of developed miscibility in fractured reservoirs. The proposed method makes it possible to evaluate gas injection processes, and developed miscibility in particular, in specific regions of the reservoir.

A systematic step-by-step extension from a single one-dimensional matrix block to more complex matrix-fracture systems shows that the minimum miscibility pressure/enrichment (MMP/MME) level in a fractured reservoir is significantly higher than for a conventional one-dimensional single-porosity system. This is mainly due to multi-dimensional flow and molecular diffusion.

On the other hand, even at pressures significantly below the fracture system MMP, substantial enhancements in the recovery rate and ultimate oil recovery can be expected by non-equilibrium gas injection. It is shown that reduction of the gas-oil interfacial tension and internal Darcy flow induced by interfacial tension gradients play a key role. This capillary driven process may lead to accelerated production and very high ultimate recoveries.
Injection Well-Producer Well Combinations in THAI 'Toe-To-Heel Air Injection'
Authors: Xia T. X. , Greaves M. , Turta A. T.
Published: December 2007

THAI – ‘Toe-to-Heel Air Injection’ is a new, short-distance displacement process, that achieves high recovery efficiency by virtue of its stable operation and ability to produce mobilised oil directly into an active section of the horizontal producer well, just ahead of the combustion front. THAI, therefore, avoids the pitfalls inherent in most conventionally operated in situ combustion (ISC) processes, which employ vertical injection-vertical producer wells to achieve longdistance displacement. However, the problem of achieving efficient ignition and start-up still requires critical attention, in order to ensure optimal process operation.

A series of 3-D tests on heavy Wolf Lake crude (10.5 °API) and Athabasca Tar Sand Bitumen (8 °API) were made using well configurations: vertical (VI) or horizontal injection (HI) and horizontal producer (HP) wells in direct line drive (VIHP, HIHP); staggered line drive (VI2HP) and line drive (2VIHP). Experimentally, the horizontal injector configuration (HIHP) was found to be the most efficient for achieving rapid start-up, i.e. the shortest time to achieve stable combustion front propagation. However, injection of air via a horizontal well is not a very practical design for field operation. The single vertical injector configuration (VI2HP) was slow to achieve stable operation, due to the development of a much smaller ignition zone, initially, compared with the HIHP configuration. When hot air was used for ignition, the time delay for oil production is related to the reservoir temperature. When the initial temperature in the sandpack was 15°C, then a vertical injector, placed high in the sandpack, combined with a horizontal producer well (VIHP) achieved slower start-up than VI2HP for post-steam flood THAI, with the initial sandpack at 100°C. All of the tests achieved very high oil recoveries, averaging greater than 80% OOIP, except in the VIHP test. The recovery in the latter case was only 70% OOIP due to the loss of air injectivity during later stages of the combustion. Significantly, THAI also preserves the very substantial thermal upgrading which occurs in the mobile oil zone, averaging an increase of 6 to 8 API points.
Estimating Geomechanical Properties Using an Integrated Flow Model
Authors: Fanchi J. R.
Published: December 2007

The purpose of this paper is to show how to estimate geomechanical parameters for improved recovery and coalbed methane production processes using an integrated flow model. An integrated flow model combines a petrophysical model with a traditional flow simulator. The usefulness of reservoir geophysical information from an integrated flow model is discussed for the following scenarios: forecasting the reservoir geophysical response of CO2 injection in a mature oil field; estimating subsidence during depletion of an oil reservoir with a gas cap; and predicting the change in geomechanical properties during the life of a coalbed methane reservoir.
Full Field Simulation of Aquifer Interdiction in the Kern River Field, California
Authors: Baumann C. E. , Osterloh W. T. , Temple R. C. , Lolley C. S.
Published: December 2007

This paper describes an efficient numerical technique and reservoir model that were developed to simulate full field aquifer interdiction strategies for reducing water influx into the production area of the "Giant" Kern River Field. The main objective of the simulation is to optimize dewatering wells’ locations and rates to increase the thermal recovery efficiency by reducing the heat loss to the influx of bottom and edge water. Other benefits are accelerated reserve recovery and increased ultimate recovery.

A novel two-phase liquid-gas model with a two-component water-oil liquid phase was implemented. Of significant importance to this modeling effort is an accurate and efficient simulation of the free liquid-gas interface. This is due to the high pumping rates of the dewatering wells, which can produce up to 60,000 BWPD, with the consequent changes in the liquid-gas interface elevation. Such changes in turn affect the fluid pressure at a considerable distance from the interdiction wells, with the consequent change in the reservoir fluid flow. The liquid-gas interface is simulated with a numerical technique capable of tracking the liquid-gas interface across gridblocks. This numerical model delivers accurate simulations of the liquid-gas interface movement using relatively coarse grids, making possible to perform full field simulations on desktop computers.

Very good observation wells’ pressure matches have been obtained, and performance predictions indicate that at least 25% aquifer water interdiction efficiency is possible, with the consequent increase in thermal recovery efficiency.
An Alternative View of Filter Cake Formation in Fractures
Authors: Seright R. S.
Published: December 2007

A new model was developed to describe water leakoff from Cr(III)-acetate-HPAM gels during extrusion through fractures. This model is fundamentally different than the conventional filter cake model that was used during hydraulic fracturing. Even so, the model accurately predicted leakoff during extrusion of a guar-borate gel. Thus, the new model may be of interest in hydraulic fracturing.

For a Cr(III)-acetate-HPAM gel, pressure gradients and gel dehydration during extrusion were similar at 20°C, 40°C, 60°C, and 80°C. Similar gel dehydration behavior was observed over a three-fold range of concentration for Cr(III)-acetate-HPAM gels. During extrusion, measurements of pressure gradient versus HPAM concentration paralleled those of elastic modulus versus HPAM concentration.

In 0.04-in.-wide fractures, gel mobilization during brine injection (i.e, gel washout) occurred at pressure gradients similar to those during gel injection. In wider fractures (0.08-and 0.16-in.), Cr(III)-acetate-HPAM gels experienced mobilization at lower than expected pressure gradients. We explored how incorporation of particulate matter into gel affects washout from fractures. Shredded polypropylene and fiberglass insulation dispersed well in Cr(III)-acetate-HPAM gelants and gels. In contrast, mica, nut plug, diatomaceous earth, and celloflakes experienced severe gravity segregation. Incorporation of 0.1%-0.2% fiberglass insulation into Cr(III)-acetate-HPAM gels reduced gel washout during subsequent brine injection. However, improved formulations are needed to prevent washout for fractures that are wider than 0.08 in.
Analytical Matrix-Fracture Transfer Models For Oil Recovery by Hindered-Capillary Imbibition
Authors: Civan Faruk , Rasmussen Maurice L.
Published: December 2007

The previous matrix-fracture transfer models overlooked the effect of the fracture surface conditions on oil recovery by water imbibition. This paper presents an improved matrix-fracture-transfer model and approximate analytical solutions for waterflooding of oil reservoirs by hindered-capillary imbibition into matrix blocks surrounded by natural fractures. The rectangular and spherical type simpler shapes are considered to represent the matrix blocks formed by intersecting fractures. The immiscible displacement equations are simplified by means of the unit-end-point-mobility-ratio approximation and solved analytically. The restricted and hindered capillary imbibition phenomenon is considered in order to account for the finite-skin effect of the matrix block surfaces by various processes, including the formation of a stationary fluid film or an actual skin because of formation damage by various processes, such as deposition of minerals and other debris, and adverse rock-fluid interactions. Then, full scale, and short and long-term analytical solutions are presented and validated by experimental data.

By means of these analytical models, various laboratory experimental data are analyzed, and it is demonstrated that the condition of the matrix block surface is an important factor in hindering the rate of water imbibition into matrix blocks and the matrix-to-fracture oil expulsion, and therefore reducing the oil recovery factor. Comparison with previous simplified models shows that the present model is superior and can accurately predict the matrix-to-fracture oil transfer over the full range of the oil recovery period, while the previous models can only represent either the early- or the late-time behavior with limited accuracy. In addition, the effect of the reservoir rock wettability on the rate of oil recovery by hindered-capillary imbibition is investigated by means of the capillary dispersion coefficient, determined by correlating the experimental data using the new models. This study reveals that there is a strong relationship between the oil recovery factor and the capillary dispersion coefficient.

The analytical models developed here can be utilized for rapid prediction of oil recovery from naturally fractured reservoirs undergoing a water flooding process.
Impact of Fracture Permeability on Oil Recovery in Moderately Water-Wet Fractured Chalk Reservoirs
Authors: Graue A. , Nesse K. , Baldwin B. A. , Spinler E. A. , Tobola D. P.
Published: December 2007

The impact of fracture permeability on oil recovery from moderately-water-wet chalk has been determined. Nuclear Tracer Imaging was used to measure local fluid movement and to identify locations of trapped oil resulting from waterflooding a sleeved, fractured chalk block. Increasing the confinement pressure between experiments decreased the permeability of an interconnected fracture network for each sequential waterflood. The experiments showed that the dominant oil recovery mechanism was spontaneous imbibition, however, viscous oil recovery added significantly to the total oil production when the permeability ratio between the fractured system and the matrix was less than 20. The amount of oil viscously recovered increased as the fracture permeability decreased.
Improved Hydrocarbon Recovery in the United Kingdom Continental Shelf: Past, Present and Future
Authors: Jayasekera A. J. , Goodyear S. G.
Published: December 2007

Gas production from the UKCS commenced in 1967 and oil production in 1975. The North Sea area is now very much a mature province with the large fields in the Southern, Central and Northern North Sea producing at significantly below their early plateau production rates. Here the drive is to maximise the overall economic hydrocarbon recovery from the province, by making the best use of the infrastructure that has been built up to bring in new discoveries and improve recovery from the mature fields. New areas (deeper, harsher climate) are being opened up for exploration on the Atlantic Margin.

This paper reviews the evolution of the mature areas of the UKCS, with case studies to illustrate the technical challenges that have been overcome. Over the years government and industry have expended considerable resources in developing innovative techniques for improved hydrocarbon recovery. These range from developments in the application of EOR processes to advances in drilling and reservoir management technology, including novel seismic techniques to identify new or bypassed oil. Technological advances have also unlocked reserves in heavy oils and in high-pressure high-temperature (HPHT) condensate fields, which were left undeveloped until the 1990s.

Finally the potential for further exploitation and life extension of the UKCS as a significant hydrocarbon province will be reviewed. This will cover perceived technology gaps in opening up the new areas in deeper water, opportunities for redeveloping mature fields using new technology, combining IOR with carbon dioxide sequestration, and the need to drive down costs to be competitive in the international arena, while honouring environmental commitments.
Conditions for Foam Generation in Homogeneous Porous Media
Authors: Dicksen Tanzil , Hirasaki George J. , Miller Clarence A.
Published: December 2007

The generation of strong foam in homogeneous porous media has been reported to be a function of flow rate, pressure drop, permeability, and system length. This study seeks to explain foam generation in terms of dimensionless groups and establish the criteria for foam generation based on the mobilization of stationary foam lamellae.

Steady-state theories and experiments in the literature suggested the existence of a critical pressure gradient for foam mobilization that is inversely proportional to permeability. Experiments involving transient displacement of surfactant solution with gas injection, however, revealed a critical pressure drop that is inversely proportional to the square-root of permeability. The observation led to a new criterion for mobilization and foam generation in transient experiments, that the pressure drop across the displacement front must exceed the pressure drop to mobilize a single lamella.
Micromodel Studies of Polymer-Enhanced Foam Flow Through Porous Media
Authors: Romero C. , Alvarez J. M. , Müller A. J. , Bolívar U. Simón
Published: December 2007

In recent years the use of polymer-enhanced foams (PEFs) and gelled foams has become a focus of interest for gas shut-off control. Many studies have focused in evaluating the blocking ability and rheology of these PEFs before applying them in the field, but a bigger effort still has to be done in understanding the flow behavior of these fluids, which are much more complex in nature than conventional foams.

In this paper we present new micromodel studies that have been conducted with PEFs in constricted capillaries. Experiments were carried out using an alpha-olefin-sulfonate (AOS) foaming agent and five different polyacrylamides varying molecular weight, hydrolysis content and functionality. New data indicates that PEFs show a different flow behavior than that reported for conventional foams and that existing foam models may have to be reviewed to simulate PEF flow through porous media.

In 1992 Osterloh and Jante1 had identified for conventional foams the presence of two distinct flow regimes when flowing through porous media: a high quality regime where pressure gradient was independent of gas flow rate, and a low quality regime in which pressure gradient was independent of liquid flow rate. Alvarez, Rivas and Rossen2 later confirmed this to be a part of a general foam behavior.

In our studies, we found indications of the presence of these two foam flow regimes for conventional foams in constricted capillaries, while all PEFs showed under this geometry a completely different behavior, where the high quality regime seemed to be absent.

These results could indicate that capillary pressure and coalescence do not govern PEF flow in porous media, as it does for conventional foams. Micromodel studies however, might not be directly applicable to flow in real reservoir conditions, but implications of the results here published could be useful in understanding the behavior of these fluids. Due to the simplicity of the pore geometry, these results can also assist in the evaluation of existing foam flow models for PEF flow, or in the future development of new models to understand the physics involved in the flow of these complex fluids through porous media.
Improved Oil Recovery by Flank Waterflooding in the Lagunillas 07 Reservoir, Venezuela: A Case Study
Authors: Agbon I. S. , Ramones M. , Patniyot S. , Chang R. , Chek-Yan N.
Published: December 2007

The Lagunillas 07 reservoir is located Lake Maracaibo in Venezuela. The reservoir contains the Laguna, Lagunillas and La Rosa formations. The sands are of the Miocene age, poorly consolidated, well sorted and fine-grained. The oil had an 18° API and a viscosity of 21 cp at initial conditions. Oil production began in 1926 and more than 1,000 wells have been drilled. Flank waterflooding, at an average water injection rate of 100,000 stb per day, was introduced for pressure maintenance purposes in 1984. By December 1999, cumulative water injected was 558 million barrels and 36.7 % of the initial oil in place had been produced.

This paper evaluates the impact of the flank waterflooding project in the Lagunillas 07 reservoir. The net oil recovery due to the flank waterflooding is estimated. The real time water front movement is determined with a front-tracking technique that uses fluid production data. The movement shows water fingering due to reservoir heterogeneity. A good match is obtained when the water front movement is cross-correlated with the petrophysical properties of the reservoir. Finally, the impact of the flank waterflooding on recovery factor is highlighted.

The paper concludes that a net oil recovery of 17 million barrels can be attributed to the flank waterflooding from 1984 to 1999. A net oil recovery of 160 million barrels is expected if the flank waterflooding is continued until 2019. The flank waterflooding is therefore considered a success. A future development plan is proposed for the reservoir.