bluuebunny/crossref_metadata_2025 huggingface dataset:
Minimum Air and Water Flow Rates Required for Effective Cuttings Transport in High Angle and Horizontal Wells
Authors: Vieira P. , Miska S. , Reed T. , Kuru E.
Published: December 2007

Many studies have been conducted to determine the optimal hydraulic conditions when conventional fluids are used in drilling operations. However, little information is available for cuttings transport when gasified fluids are used as a drilling fluid. Since deviated and horizontal-well drilling are becoming more common and are frequently combined with the use of non-conventional drilling fluids, such as gasified fluids or aerated muds, a better understanding of the cuttings transport phenomena is needed for these applications.

This study was conducted to help filling this gap and to gain more in-depth understanding of cuttings transport in horizontal and highly-inclined wells when using gasified fluids. Extensive experiments were performed in a unique field-scale low-pressure flow loop (8″ × 4.5″, 90′ long) at horizontal and inclination angle of 80 degrees from vertical. Gravel with 3.29 mm average diameter was used to simulate drill cuttings and water and air were used as the liquid and gas phase. The three phases were injected into the test section of the flow loop, at different volumetric flow rates combinations, for the horizontal and 80 degree inclination angle. Pressure drop, annular pressure, temperature and cuttings accumulation were recorded in each experiment through a data acquisition system. Gas and fluid-interface distribution were visually observed and reported for each experiment. Likewise the solid-liquid distributions were classified into three different patterns and reported for each experiment. The effects of gas and liquid flow rates, drilling rate, inclination angle, pressure drop and flow patterns on cuttings transport were analyzed in this study.

It was observed in the experiments, for the range of volumetric flow rates used during these tests, that cuttings are only transported by the liquid phase. It was also found that it is possible to define a boundary for the minimum air and water velocities required to avoid the formation of a stationary cuttings bed. These minimum requirements exist in the intermittent flow region for the gas and liquid interface distribution. It was observed that the minimum requirements for air and water injection rates are also a function of the solids injection rate. It is postulated in this study that there is a minimum energy required for solids transport, and this is constant for a given solids injection rate. It was observed that the inclination effect for angles close to horizontal is negligible.
Intellectual Property for the Oil Field
Authors: Brewer Peter L.
Published: December 2007

This paper presents a general overview of intellectual property. Various types of intellectual property rights are identified and discussed, including patents, copyrights, trademarks, and trade secrets. The United States legal system provides enforceable property rights incident to each of these types of intellectual property. However, the corresponding property rights are distinct, and the process for protecting each type of intellectual property is very different. These differences are discussed in general terms in the paper so as to afford a foundation of knowledge for the layperson. In addition, the role of each type of intellectual property in the oil field is outlined.

This paper presents a general overview of intellectual property. The purpose is to identify different types of intellectual property recognized within the United States legal system, and to discuss intellectual property issues which oil companies and oil service companies currently face.1

Because of the complexity and sheer volume of laws and regulations which apply in intellectual property, it is not possible to provide more than a thumbnail sketch of the subject. This paper will serve as a useful reference tool for laypersons, enabling them to identify general issues as they might arise.
Offsetting Kill and Choke Lines Friction Losses for Deepwater Well Control: The Field Test
Authors: Isambourg Patrick , Simondin Armel , Studer Regis
Published: December 2007

Deepwater well control with a subsea BOP is often difficult and in many circumstances impossible with the usual methods and procedures. This is mainly due to the difficulty to maintain the circulating pressure below the low formation fracture pressure, because of high friction losses in kill and choke lines. Such a situation often leads to losing the drilled section. To cope with this situation, a new method was developed and presented in a previous paper. It consists in lightening the mud column inside the choke line by injecting base oil or water at the BOP level. Simulations using a dedicated software demonstrated the possibility to compensate lines friction losses.(essai labo ?) To validate simulations and to confirm the operational feasibility of this method, a field test was conducted on a Deepwater well in Angola. Pressures were recorded at surface, at the BOP level and downhole, and confirmed predicted values. The test was performed without any modification of the drilling rig, and no operational problems were encountered. The test fully confirmed that the method allows the physical removal of friction losses in the choke lines. The obtained downhole pressure during a well control is then lowered compared to a conventional method in all cases where the choke line friction losses cannot be removed artificially at the choke. (such as swak kick in an horizontal section). Test procedure, simulated pressures and field measurements, are detailed in this paper, and complemented by their analysis and resulting operational guide lines.
Unique Offshore Recovery System Dramatically Reduces Environmental Impact by Recycling Stimulation Proppant
Authors: Slater Martin , Perez Daniel , Teesdale Chris , Hilbig Nicholas
Published: December 2007

Over the past four years, the use of multiple-zone proppant fractures has significantly improved production and the ultimate productive life of horizontal wells in the Valhall chalk field. A typical well is designed with up to 10 proppant-fractured zones. The stimulation technique involves the pumping of as much as 300,000 lb of proppant into each zone and during this process up to 70,000 lb of excess proppant may remain in the wellbore, which is cleaned out using coiled tubing. Since the material contains a resin coating to facilitate adhesion in the reservoir, disposal is restricted.

Previously, this waste had to be collected offshore, placed in large bags, containerized and shipped to shore for incineration - a practice that was costly, wasteful and environmentally suspect. In 1997, engineering studies revealed that the properties of the waste material made it suitable for re-cycling and use in future operations with minimal impact on fracture performance. While re-using proppant has become an accepted practice with no noticeable effect on well productivity, logistically it had some limitations. The material still had to be collected offshore and transported onshore where it was stored for several months before being reloaded into the stimulation vessel for reuse in the next fracture treatment. This represents storage problems and environmental exposure of these materials. Furthermore, with no unforeseen delays, this was a 24-hour two-way trip.

This paper describes the development and successful application of a unique system that allows the excess proppant to be collected, treated and recycled on location. The authors will discuss the evolution of the recycling technique and discuss the step-change improvement that allows the material to be reused immediately offshore utilizing specialized vacuum equipment.

Some 150,000 lb of proppant was successfully recovered and recycled on the first well. The technique is still evolving and is likely to become a standard operation on Valhall wells. The offshore collection and recycling technique has eliminated the logistical problems associated with the previous method and will in time reduce the total proppant costs, along with minimizing the associated HSE impact.
Innovative Technology Improves Penetration Rates of PDC Bits in Shales Drilled at Great Depth with Weighted Water Based Mud Systems
Authors: Mensa-Wilmot Graham , Fear Martyn
Published: December 2007

Shales present lower mechanical and drillability challenges, when compared to other common lithology types such as sandstones and carbonates1,2. However the penetration rates (ROP) of drill bits, especially that of PDC bits, do not always reflect this characterization. Research efforts, focusing on shale drillability, have now revealed that bit performance in shales is much more dependent on factors such as depositional depths, mud types and mud weights than it is on hardness and/or abrasiveness3,4. The characteristics and/or magnitudes of these factors, that have adverse effects on bit performance, will be referred to as "negative performance factors" (NPF) in this paper. PDC bits usually drill twice as fast as roller cone (RC) bits in Shales. However, this ROP trend reverses when both bit types are exposed to NPF environments.

This paper will identify the causes of poor PDC bit performance when exposed to the influences of NPF environments. It will discuss an innovative technology which has specifically been developed to improve the ROPs of PDC bits in shales, especially when drilled at great depths with weighted water based mud systems. Laboratory and field data, showing the technology's positive effects on PDC bit performance will be presented. Specific laboratory tests, designed to identify operational conditions that enhance PDC bit performance in such applications, will also be discussed.
The Drilling Fluid Inhibition Properties Effect on Hole Quality - A Well Survey
Authors: Løklingholm G.
Published: December 2007

Shale inhibition is considered to be the most important factor to prevent hole problems when drilling with water based drilling fluid (WBM). Some components are believed to be vital for well bore inhibition like KCl, glycols and designed polymers. The effect of the products is largely based on the cuttings quality seen in the return flow at the rig. When new systems are introduced they are often tested in relatively simple wells and performance are evaluated based on results form that well.

Some incidental observations where systems not regarded as inhibitive outperformed the state of the art water based drilling fluid systems. This observation trigged of a larger survey on drilling efficiency with respect to water based drilling fluid system. Water based drilling fluid systems used in Statoil's operations over the last 15 years in the North Sea were compared with respect to hole quality. Data from the survey shows that today's highly inhibitive systems do not perform any better than systems used for 15 years ago. The survey raises a question around the way drilling fluid systems are designed today. Are we using the right methods for designing the drilling fluids?

The paper describes the result from the survey. In the paper a method using different "indicators" to measure the hole quality is used. Such indicators include: stuck pipe frequency, tripping time, drilling progress, caliper data and cuttings quality. As a result of the first part of the survey, the drilling fluid chemical composition was altered both when drilling through non-reactive and reactive formations in a series of wells. An increased drilling efficiency was observed. The paper describes how the drilling fluid composition could be optimized dependent on the smectite content of the formation.
Innovative Concept to Reduce the Total Cost of Scale Management through the Capture and Re-Use of Chemical Inhibitors
Authors: Feasey N. D. , Graham G. C. , Seland G. , Stalker R.
Published: December 2007

Conventional scale inhibitor squeezes are widely used to prevent or delay scale formation. Although long established the process can be wasteful of chemical used. In common with the use of most production chemicals such treatments are ‘once through’ and non-recoverable with high operating costs. In addition in offshore operations such production chemicals are discharged into the sea. Such discharges are also subject to environmental legislation with associated costs. Increasingly there is a need to avoid such discharges. Modifications of the squeeze procedure have been introduced to extend squeeze lifetime but further improvements are still sought. This paper describes the results of a study to investigate the potential for membrane separation to capture a representative scale inhibitor from brine. Over a range of temperatures, scale inhibitor concentrations and brine chemistries more than 96% of the scale inhibitor was captured. This was obtained without any attempt to optimise operating conditions. The resulting captured material was compared to the original product using dynamic tube blocking tests and static barium sulphate tests. The static tests showed similar performance for recovered and initial material, while the dynamic tests showed a marginal increase in performance for the recovered material in some cases. This increase in performance correlates with the retention factor for each given test run. It is believed that this is due to a slight purification of the inhibitor during the separation process, as shown by Dionex Ion Chromatography. The effective performance of the recovered inhibitor suggests that it could be re-used in a similar manner to the original product.
Meeting the Challenges of Downhole Scale Inhibitor Selection for an Environmentally Sensitive Part of the Norwegian North Sea
Authors: Chen Ping , Hagen Thomas , MacLean Alan , Selle Olav Martin , Stene Karin , Wat Rex
Published: December 2007

The Haltenbanken area is environmentally sensitive due to its plentiful fish reserves and licensees are therefore faced with stringent guidelines for the use of chemicals. The Heidrun Field is located within the Haltenbanken group consisting of Heidrun, Asgard and Norne. All are relatively new developments. The reservoir has a bottom hole temperature of 85°C and a relatively low reservoir pressure of 250 bar, hence seawater injection for pressure support has been utilized. With Ba2+ levels in the range from 100 to 300ppm, downhole sulphate scale deposition was identified within the formation and the gravel pack. This has been highlighted by the active squeeze campaign since spring 2000 when seawater first broke through. Different generic scale inhibitors, including one biodegradable scale inhibitor, have been deployed in the field so far.

Due to the environmental sensitivity of the area, the scale control strategy has focused on the selection of environmentally friendly, or green, scale inhibitors. Moreover, the selected green inhibitors as well as exhibiting good performance and a long squeeze life, must overcome the severe emulsion formation experienced topside during initial flowback.

In this paper, the laboratory evaluation of potential green scale inhibitors is presented and some novel inhibitor test methodology is discussed. For example, the effect of temperature on inhibitor efficiency was found to vary when the cooling method was compared with the standard method where the test sample was pre-set to a target temperature. The cooling method was therefore found to better simulate field conditions where the fluid experiences temperature drops as it travels from the formation to surface. Also, in the inhibitor adsorption/desorption study, the static beaker tests were found to be an effective method of testing inhibitor adsorption properties for quick screening. While traditional beaker tests focus on the inhibitor adsorption, the inhibitor desorption property is usually studied using core floods. In this paper we shall present a new methodology based on bulk desorption tests. This has been used, in addition to the conventional core test, for our chemical selection. The field inhibitor squeeze return data demonstrated that the newly selected inhibitor offered an improved squeeze life than that previously experienced on Heidrun.
How is Scale Prevention Affected by the Late Field Depressurisation of Waterflooded Reservoirs?
Authors: Mackay E. J. , Agiddi D. , Graham G. M.
Published: December 2007

A number of mature waterflooded fields, such as Brent in the North Sea and others elsewhere are undergoing tertiary recovery by depressurisation Pressure depletion is achieved by stopping water injection and by producing from the aquifer as well as the hydrocarbon bearing strata. Previously bypassed oil rims and trapped oil and gas are then released. This paper discusses how mineral scale deposition is affected by the change in reservoir conditions that occur during blow down.

Pressure maintenance by waterflooding may prevent reservoir fluids from dropping below the CO2 bubble point until they are in the production string. However, as a result of depressurisation, the CO2 bubble point will move down the tubing and into the formation. Calcite scales form as a result of the increase in pH that occurs when CO2 is evolved, and thus the calcite scaling problem will migrate into the near production well formation during depressurisation. The balance of oil-water and gas-oil capillary pressures changes with pressure depletion, resulting in the mobilisation of previously trapped formation brines. Waterflooding also results in large volumes of seawater being injected into the oil bearing strata. During depressurisation, this seawater is back produced through the former injectors. Depending on the strength of the aquifer, formation brine may also be produced. If these brines are incompatible, then mixing in the wellbore or near well formation will result in sulphate scale damage. Calculations demonstrate that co-production of aquifer and injected brines may occur for more extensive periods at the critical mixing ratios than would be typical of conventional production scenarios. Former injection wells will produce at near 100% watercuts, with the result that large volumes of water need to be protected. Calculations of reservoir temp eratures and the scaling potentials show that the problem is exacerbated by the fact that during water injection these zones will have been cooled.
Real-Time Method for the Detection and Characterization of Scale
Authors: Poyet Jean-Pierre , Segeral Gerard , Toskey Eric
Published: December 2007

A new technique is presented to detect scale deposition and to determine its composition and thickness in real-time in oilfield tubing and pipe. The method is based on continuous triple energy gamma-ray attenuation measurements made at a dedicated, instrumented mandrel or spool piece. Detection and identification of extremely thin scale deposits are possible without disrupting the flow. Simulations of scale deposits in a three-phase pipe are given to demonstrate the method’s practical application. The feasibility of the method has been verified with field measurements. The instrumentation required is based on existing technology with a proven track record in field conditions. Surface installations are safe to operating personnel and the environment.

This new method enables a simple monitoring device to detect and characterize scale in its earliest stages of formation. The technique may be used to determine the appropriate type of inhibition or removal treatment according to the type of scale present, to evaluate the effectiveness of scale treatments in-situ in the pipe in real-time, and can help to optimize chemical consumption for continuous treatment.
Role of Impermeable Layers in Barium Sulphate Oilfield Scaling: Modelling & Field Study
Authors: Bedrikovetsky P. , Rosario F. , Bezerra M. , Silva M. , Junior R.
Published: December 2007

Several different scenario of injected and reservoir water mixing have been proposed: mixing at high velocity near to injectors, mixing at low velocity inside reservoirs, mixing by diffusion via boundaries of layers with different permeabilities, mixing of injected, connate and aquifer waters at high velocity near to producers. Just the latter mechanism results in the accumulation of formation damage, while other mechanisms cause precipitation near to moving concentration front. In the current paper a new mechanism of oilfield scaling by diffusion of Barium from impermeable layer into the reservoir is proposed. The mechanism results in accumulation of precipitant and of formation damage.

Viscous dominant regime of waterflooding takes place in the majority of oil fields. The Welge´s method allows calculating the permeability distribution from water cut history. The proposed extension to Welge´s method determines the partition of permeable layers in a reservoir from tracer concentration in production wells. Knowledge of this partition is important for modelling of oilfield scaling accounting for Barium supply from impermeable layers.
An Assessment of Adhesion of Scale and Electrochemical Pre-treatment for the Prevention of Scale Deposition on Metal Surfaces
Authors: Labille S. , Neville A. , Graham G. M. , Boak L. S.
Published: December 2007

From an oilfield scale prevention perspective, interest recently has focused on understanding the relationship between heterogeneous nucleation and growth on pipeline surfaces (adhesion) rather than homogeneous nucleation and growth from bulk solution. Furthermore, it is recognised that homogeneous nucleation, and not adhesion, is conventionally examined in industry standard bulk "jar" type tests for the assessment of scale inhibitor performance. The trend towards understanding heterogeneous nucleation and growth has gained interest because scale adhesion is recognised as a much more serious issue than homogeneous "bulk" precipitation.

In a recent paper by Neville et al.1 a novel electrochemical approach, has been described which enabled the extent and also the rate (kinetics) of CaCO3 and BaSO4 scale formation on a solid surface to be determined. During this study it was clearly shown that the formation of an inhibitor film at a metal surface can occur and the extent of this is affected by the presence of certain cations, the inhibitor concentration and the hydrodynamic and electrode potential regimes. In laboratory studies on rotating disk electrode (RDE) coupons it has been clearly demonstrated that this film has a beneficial effect in preventing scale formation from a supersaturated solution onto a metal surface.2,3 As such there is potential to enhance scale inhibition by carrying out an electrochemical pre-treatment.

In this paper the research has been extended to include pre-treatment of surfaces in a dynamic tube-blocking rig. The effect of various pre-treatment parameters on carbonate scale have been assessed and it has been shown that even in the higher temperature and pressure environment there is a benefit of using electrochemical pre-treatment.

In addition, the paper summarises other work conducted by the authors which examines the relationship between heterogeneous nucleation and growth on pipeline surfaces (adhesion) rather than homogeneous nucleation and growth from bulk solution which includes the impact of conventional scale inhibitors and film forming corrosion inhibitors.
Lessons Learned from Descaling Wells in a Sandstone Reservoir in Saudi Arabia
Authors: Nasr-El-Din H. A. , Lynn J. D. , Hashem M. K. , Bitar G. E. , Al-Ali A. A.
Published: December 2007

Abstract Description of Paper

This paper describes the development and field application of an acid-based treatment to remove downhole scale in several oil producing wells in a sandstone reservoir in Central Saudi Arabia. The sandstone reservoir is weakly consolidated and sanding problems were noted in several wells. To avoid sanding problems, these wells were gravel packed. In addition, the reservoir pressure and gas oil ratio are low and, as a result, electrical submersible pumps (ESP) are used to produce these wells. The sandstone reservoir contains 1-13.5 wt% clay minerals and the bottom hole temperature is 160°F. A thorough investigation was undertaken to identify the composition and location of the scale, to recommend a suitable acid formulae to remove the scale, and to assess the effectiveness of the treatment in the field.

Based on extensive lab studies, an acid treatment was designed and applied in more than 15 wells. These wells have a water cut that ranges from 3 to 80 vol%. Because of the low reservoir pressure, these treatments were conducted using coiled tubing and the spent acid was lifted using nitrogen gas. In addition, the formation is water-sensitive. Therefore, the pre and post flushes were designed to minimize formation damage due to fines migration and clay swelling. Chemical analysis of acid returns (spent acid) was used to determine the type and concentration of acid additives.
HPHT Wells Create New Challenges Demanding Higher Levels of Coiled Tubing Inspection and Management
Authors: McCoy T. , Rosine R. , Aulert C. , Martin J. , Stanley R. K.
Published: December 2007

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

A critical requirement for directional drilling with coiled tubing (CT) is a reliable downhole means to manipulate the orientation of the mud motor bend. Alaskan operations have traditionally used hydraulically actuated ratcheting orienters, thus avoiding the complications of wireline and control lines inside the coiled tubing. With highly refined field techniques and well plans, the fundamental drawbacks to these orienters have been adeptly managed on the North Slope.

Despite good success over the years, drilling and orienting have remained mutually exclusive activities. As such, orienting becomes nonproductive time (NPT) when it cannot be combined with necessary hole conditioning and wiper trips. While orienting problems and failures have been increasingly common in deep and high-build-rate applications, perhaps the most significant challenge to the standard hydraulic orienter service for coiled tubing drilling (CTD) is lost circulation.

Initial steps in the development of an intelligent wireless orienter for CTD were taken in 1999 with the goal of eliminating off-bottom orientation, a significant source of NPT for Prudhoe Bay operations. Subtle computer-controlled mud pump variations are the basis for a versatile downlink command structure used to drive the downhole actions of the turbine orienter. The benefits of the prototype orienter were confirmed during a promising field trial beginning in late September 2001. As of December 2001, the novel service has been used on eight wells in Prudhoe Bay. This paper describes the turbine orienter development program, testing, a quantification of benefits, reliability figures, lessons learned, and future plans.
Underbalanced Coiled-Tubing Technique Leads to Improved Productivity in Slotted Liner Completions
Authors: Hibbeler Jeff , Duque Luis , Castro Luis , Gonzalez Alexis , Romero Jorge
Published: December 2007

Sand production is a well-known and costly problem in shallow unconsolidated sands. For years slotted liners have been used to control sand in these types of reservoirs. However, over time sand, fines and other debris can clog slots or make their way into the liner itself, thus blocking production. A new live-well intervention technique making use of a concentric coiled tubing (CCT) vacuum tool (VT) has been implemented in Venezuela1,2,3. The technique incorporates a venturi jet pump mounted on CCT, and is specifically designed to remove solids and/or fluids from the wellbore without placing hydrostatic loads on the reservoir. In sand vacuum mode, strong jets fluidize and mobilize solids into the vacuum as well as prevent a stuck pipe scenario. The jets also aid in opening clogged slots by loosening fines that may be blocking flow. When the VT applies suction, a localised pressure-influenced-zone is formed in the very near wellbore – thus providing an isolated ";point-load"; drawdown on the formation.

The jetting action combined with point-load drawdown and drag forces results in solids removal from behind pipe as well as inside pipe. Evidence of this phenomenon are jobs where a solids volume greater than the entire liner has been retrieved to surface. Post job results on jobs performed in Venezuela consistently show reduced skin, increased Productivity Index (PI) and higher long-term oil production.

This paper describes the latest in CCT vacuum technology as well as it improvement in time via case studies of several different applications in Venezuela. Also discussed are simple lab techniques, which reveal serious completion issues such as liner slot erosion, fines invasion and drilling fluid damage.
Field Application of Relative Permeability Modifier in Venezuela
Authors: Nieves Gustavo , Fernandez Jenny , Dalrymple E. Dwyann , Sierra Leopoldo , Eoff Larry , Reddy B. R.
Published: December 2007

For many years, relative permeability modifiers (RPM's) have received a great deal of attention from the oil and gas industry. Because of the completion techniques used in many wells, protecting the hydrocarbon interval properly during a watershutoff treatment is not always practical or cost effective. RPM's offer the option of bullheading a treatment without zonal isolation, which is designed to decrease water production with little or no decrease in oil or gas production.

This paper describes the laboratory development and optimization of a polymeric RPM. The resulting material can best be described as a brush polymer consisting of a polymeric backbone grafted with methoxypolyethylene glycol (MPEG). Various phases of the development are discussed, and an overview of the laboratory evaluations is also provided. These test results indicate that the RPM polymer should be placed with a systematic approach consisting of proper preflushes and post-flushes for optimum results. A field case study in which the system was used in Venezuela is provided, along with the subsequent results of the treatment.
The Effect of Heterogeneity on In-Situ Combustion: The Propagation of Combustion Fronts in Layered Porous Media
Authors: Akkutlu I. Yücel , Yortsos Yannis C.
Published: December 2007

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

Experiments were conducted to study the feasibility of using propane as a steam additive to accelerate oil production and improve steam injectivity in the Hamaca field, Venezuela. The experiments utilized a vertical injection cell into which a mixture of sand, oil and water was tamped. The Hamaca oil sample had an oil gravity of 8°API and a viscosity of 25,000 cp at 50°C. The injection cell was placed inside a vacuum jacket, set at the reservoir temperature of 50°C. Superheated steam at 170°C was injected at 3.5 ml/min (cold-water equivalent) simultaneously with propane at the top of the cell. The cell outlet pressure was maintained at 50 psig. Four propane:steam mass ratios were used, namely, 0:100 (pure steam), 2.5:100, 5:100, and 10:100. Produced liquid samples from the bottom of the cell were collected, treated to break emulsion, and analyzed to determine oil and water volumes, and density and viscosity of the oil. The oil was subjected to SARA analysis to determine the degree of in-situ oil upgrading. Composition of the produced gas was determined using a gas chromatograph. Each run lasted three hours.

Experimental results indicated the following. First, with steam-propane injection, start of oil production was accelerated by 17% compared to that with pure steam injection. In the field, this could translate into significant gains in discounted revenues and reduction in steam injection costs. Second, steam injectivity with propane as an additive was up to three times higher than that for pure steam injection. Third, oil production acceleration and injectivity increase were practically the same for runs with propane as a steam additive (irrespective of the propane:steam mass ratios). Propane appears to be a viable steam additive at propane:steam mass ratios as low as 2.5:100.
Improved Measurement of Gas Diffusivity for Miscible Gas Flooding Under Nonequilibrium vs. Equilibrium Conditions
Authors: Civan Faruk , Rasmussen Maurice L.
Published: December 2007

Physically and mathematically rigorous improved models, considering equilibrium and nonequilibrium diffusion gas transport in the liquid phase and resistance of the gas-liquid interface to gas dissolution in liquids, are developed. This allows the accurate determination of the gas diffusion coefficient from experimental measurements of the gas pressure decline in a closed tank by dissolution of gas in the liquid. The short- and long-time solutions of these models are derived analytically under various conditions. These solutions are reformulated for direct determination of the best estimate of the diffusion coefficient by regression of the resultant analytical expressions to experimental data. Procedures are presented and demonstrated for accurate estimation of the gas diffusivity coefficient by conforming the present models to experimental data.

The results developed in this paper can be utilized for determination of the gas diffusivity and the rate of dissolution of the injection gases used for secondary recovery and the rate of separation of light gases from reservoir oil and brine. The present analytic expressions can be facilitated to establish the significance of the equilibrium vs. nonequilibrium conditions under in situ conditions for gas injection, including carbondioxide, nitrogen, and methane. The gas diffusivity in drilling muds and completion fluids can also be determined using the present analytical interpretation methods.
Gas Segregation During WAG Injection and the Importance of Parameter Scaling in Three-Phase Models
Authors: Hustad Odd Steve , Kløv Trygve , Lerdahl Thomas Rage , Berge Lars Inge , Stensen Jan Åge , Øren Pal-Eric
Published: December 2007

Saturation histories from simulations on a mesoscopic-scale heterogeneous model at immiscible and miscible conditions are compared with emphasis on gas segregation. Selected models for three-phase flow, and scaling of the end point saturations, relative permeabilities, and capillary pressures have been applied. The flow parameters of the facies were obtained from pore scale network modeling with input from North Sea sandstones. The simulation cases included water, gas, and water-alternating-gas (WAG) injection.

Gas injection at irreducible water saturation demonstrates stronger gas segregation as the pressure exceeds the minimum miscibility pressure (MMP). Gas segregation is not so evident at the mesoscopic scale during WAG injection. High water saturation in the set-planes hampers the vertical gas flow. A bank of high oil saturation forms in front of the advancing gas at miscible conditions. Oil segregates to the set-plane below and the water cycle that follows mobilizes the accumulated oil.
A Novel Mechanism for Improving Gas Conformance
Authors: Irani Cyrus A. , Hilliard J. S. , Cude S. A.
Published: December 2007

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

The application of heated water injection in a conventional oil reservoir under secondary recovery has received sparse review in the literature. In general, such a scheme can be difficult to justify. This is often due to both the additional capitalization and fuel costs offsetting the potential advantages that can be practically achieved for the effects of the differential water temperature to that of the formation. However, under appropriate circumstances, hot water injection can provide a significant advantage for secondary recovery that may warrant further investigation.

As a case study, the Senex field of northern Alberta, Canada contains a 37°API crude with high paraffin content in a low permeability shelf carbonate. The oil is essentially saturated with paraffin at the reservoir temperature of 36 C. Paraffin precipitation within the reservoir porosity accounts for declining production rates, which have been commonly treated and temporarily reversed with an extended history of chemical and solvent squeezes.

Due to the northern latitude of the field, source water has been injected at ambient temperatures to within several degrees of the freezing point for up to 7 months of the year. The impact of this operation on injector and reservoir performance proved to be of concern after an injection well appraisal revealed an extended loss of injection capacity in the early startup of waterflooding operations. Subsequently, the thermal implications for the viscous forces to the reservoir dynamics in waterflooding were studied in a numerical simulator, which demonstrated this mechanism for recovery impairment. In addition, a qualitative assessment of the further thermal implications for deterioration of reservoir performance from paraffin deposition was established. In order to test and further validate the conclusions of this analysis, a pilot hot water injection scheme was initiated in April, 2001.

This paper will describe the aspects of planning, testing and modeling that were completed prior to the field implementation of this project. Preliminary field results are also presented.
Geologically Based Screening Criteria for Improved Oil Recovery Projects
Authors: Henson Richard , Todd Adrian , Corbett Patrick
Published: December 2007

The choice of an Improved Oil Recovery (IOR) process for use in a particular reservoir depends on several factors; the habitat of residual oil, the properties of the reservoir fluids, reservoir conditions and reservoir heterogeneity.

Reservoir heterogeneity exists at all scales, from the micro to the mega-scopic. Previous workers have studied the effects of micro and meso-scale heterogeneities on IOR processes in detail, as many processes are designed to act at those scales, but have ignored macro-scale heterogeneities such as facies variations. These can have a large effect on an IOR process; controlling the magnitude and nature of the connectivity between wells, compartmentalising the reservoir and influencing the balance of capillary, viscous and gravity forces.

A database of 499 IOR projects in clastic reservoirs was collated. The macro-scale heterogeneity present in each reservoir was categorised by depositional environment using the Tyler and Finley Heterogeneity Matrix. The results show that successful IOR projects using a particular process cluster at certain combinations of lateral and vertical heterogeneity.

To investigate the distributions, a quantitative method of evaluating macro-scale heterogeneity was devised. These Lateral and Vertical Heterogeneity Indices (LHI and VHI) provide a simple method of summarising and communicating geological information between different people and disciplines.

Reservoirs with known levels of LHI and VHI were modelled, in which various IOR processes were simulated. Over 350 simulations of steam, polymer and Water Alternating Gas (WAG) injection processes were run and used to identify the processes that worked best under different levels of heterogeneity, dip and net to gross. The results showed that the Heterogeneity Indices can be used to predict the effect of macro-scale reservoir heterogeneity on these three processes and that objective, geologically based screening criteria could be derived. Using these criteria, it is demonstrated that in the high cost and low well density environment of the North Sea, WAG injection is the most viable IOR process, as the efficiency of the process is relatively unaffected by macro-scale heterogeneity.
Foam-Assisted WAG: Experience from the Snorre Field
Authors: Skauge A. , Aarra M. G. , Surguchev L. , Martinsen H. A. , Rasmussen L.
Published: December 2007

The Foam Assisted WAG (FAWAG) has been a large-scale demonstration of foam for gas mobility control. Foam has been applied at the Snorre, North Sea Brent-type sandstone reservoir, for different purposes. First initiated as a gas shut-off production well treatment, thereafter as two large-scale gas mobility control processes.

Combined water and gas injection (WAG) is the main oil recovery method at the Snorre field. Early gas breakthrough in some production wells has limited the oil production. Gas production control is one of the major reservoir management challenges on Snorre. Foam for mobility control has the potential to improve gas sweep in the Snorre WAG process.

Results from the last trial on the Western fault block were very conclusive. Gas breakthrough was delayed, but equally important the Gas-Oil-Ratio (GOR) was considerable lower than gas injection cycles prior to the foam treatment. The paper summarizes all the foam field trails at the Snorre field, with emphasis on interpretation of the last foam application on the Western fault block.

The Snorre FAWAG is the world's largest application of foam in the oil industry. The logistics involved transport of 2000 tons of chemicals from central Europe to the field location. The application of FAWAG has qualified foam as a gas mobility agent for North Sea reservoirs. Large volumes of gas have been stored in the reservoir. The expenses for FAWAG on Western Fault block (WFB) was 1M USD, and additional oil recovery value was ∼ 25-40M USD at current oil prices.
Use of the Method of Characteristics to Study Three-Phase Flow
Authors: González Marta , Araujo Mariela
Published: December 2007

Numerical simulation of multiphase flow is the most acceptable method for the prediction of oil recovery. Recently, the modeling of the three-phase flow has become critical since it may occur in a variety of conditions such as when gas is injected in a reservoir, or when gas or condensate appears as the reservoir pressure drops. Gas injection includes hydrocarbon gas, CO2, air, nitrogen or steam injection as well as WAG or gravity drainage. For such processes, the modeling of fluid displacement must include hysteresis in the relative permeability curves.

In this work, the method of characteristics is used to study the effect of rock geometry and wettability condition on the saturation paths for a three-phase system. With this method the partial differential equations used to describe fluid transport are converted into a set of ordinary differential equations which are integrated simultaneously. The method gives information about the flow behavior (fractional flow curves) and the saturation trajectories represented on a ternary diagram.

Imbibition and drainage processes are modeled using relative permeability curves calculated with a fractal pore model, on samples of strong wettability contrast: water wet, intermediate and oil wet respectively. The effect of the rock geometry and wettability condition on the saturation trajectories is analyzed.

Herein, the most relevant contribution of this work is a fast and accurate method to study the gemoetry and wettability effects on three-phase flow properties, such as relative permeability. These properties are relevant for the understanding of oil production and the design and selection of the more appropriate oil recovery strategies.