Summary. The stability of foam lamellae is limited by capillary pressure. Consequently, as the fractional flow of gas in a foam is raised at a fixed gas velocity, the capillary pressure in a porous medium at first increases and then approaches a characteristic value, here called the "limiting capillary pressure." If the gas fractional flow is increased after the limiting capillary pressure has been attained, coalescence coarsens foam texture, the liquid saturation remains constant, and the relative gas mobility becomes proportional to the ratio of gas-to-liquid fractional flow. The limiting capillary pressure varies with the surfactant formulation, gas velocity, and permeability of the medium. Introduction The mobility of a gas flowing through a porous medium is lower when it is dispersed within a liquid as a foam. Consequently, foams can improve volumetric sweep in oil-recovery processes that use gases. To apply foams optimally, the factors that influence their transport must be understood. Previous research has shown that the mobility of a foam depends heavily on its texture, which is the distribution of bubble sizes within the dispersion. The texture of foam, in turn, is governed by mechanisms that generate and destroy bubbles inside porous media: capillary snap-off and division create bubbles, while mass transfer between bubbles resulting from condensation/evaporation or diffusion and coalescence (lamella rupture) diminish bubble density. Falls et al. recently developed a model to describe the rate of foam generation by capillary snap-off and demonstrated how it could be used to simulate foam generation and flow in a simple, one-dimensional displacement. We report here the initial steps toward achieving the same level of understanding for coalescence. On the basis of how soap films and bulk foams behave, we hypothesize in particular thatthe rate of coalescence of foam bubbles lamellae in porous media depends on capillary pressure andlamellae in porous media cannot withstand capillary pressures above a porous media cannot withstand capillary pressures above a limiting value. The way this limiting capillary pressure should influence the transport of foams through porous media is subsequently detailed. Finally, experiments in which capillary pressure and foam mobility are measured concurrently are reported; these confirm that capillary pressure does indeed play a major role in determining coalescence and phase mobilities of foams in porous media. Capillary Pressure's Role In Foam Stability Outside Porous Media The behavior of soap films is described qualitatively by Derjaguin-Landau-Verwey-Overbeek (DLVO) theory, the classic theory of colloid stability. When gas/liquid interfaces are present, ionic surfactant molecules from an aqueous solution adsorb preferentially at the interfaces, thereby creating charged surfaces. The overlap of the electric fields from these charged layers imparts stability to a foam lamella. Long-ranged, attractive van der Waals forces tend to destabilize the system.DLVO theory considers how double-layer repulsion balances against the van der Waals forces. Films that are stable to small perturbations result only when the repulsive forces are stronger that perturbations result only when the repulsive forces are stronger that the attractive ones. Imposing capillary pressure (capillary pressure is the difference between gas- and liquid-phase pressures) on a lamella forces the charged surfaces closer to one another. The double-layer repulsion must balance the van der Waals forces plus the capillary pressure. As the capillary pressure is raised, the work required to break the film decreases. At a sufficiently high capillary pressure, this work may become so small that mechanical disturbances or even thermal fluctuations may rupture the film.DLVO theory thus predicts that capillary pressure should play a role in determining the stability of foams outside porous media. This conclusion is backed by experimental studies of how capillary pressure affects that lifetimes of soap films and bulk foams. These suggest that there is a characteristic capillary pressure above which the lifetimes of lamellae become exceedingly pressure above which the lifetimes of lamellae become exceedingly short. The value of the "critical" capillary pressure varies with the surfactant formulationi.e., the type and concentration of surfactant and electrolyte. Critical capillary pressures found by Khristov et al. for single films and bulk foams made from 0.001 M sodium dodecyl sulfate solutions are recorded in Table 1. The critical capillary pressure increases as the concentration of sodium chloride is raised. pressure increases as the concentration of sodium chloride is raised. At first glance, this would appear to go against what is expected from DLVO theory: at higher electrolyte levels, the length over which the electric field from the charged surfactant layers decay should shorten and the repulsive forces should weaken. This effect may be offset, however, because salt raises the surface concentration of surfactant at the gas/liquid interfaces. (NaCl's ability to raise the critical capillary pressure of foam films may explain why salt must be added to enable some steam-foam-forming surfactants to reduce steam Mobility.)Khristov et al. also noticed that bulk foams break at lower capillary pressures than do single films created from the same solution. They attributed this tothe films in the bulk foams having larger radii than the single to and"collective effects," where disturbances from the rupture of one film cause its neighbors to break. Concepts and Consequences of a Limiting Capillary Pressure for Foam In Porous Media The stability of foams in porous media may likewise depend on capillary pressure. In porous media, however, all lamellae do not simultaneously coalesce at some "critical" capillary pressure. Instead, because lamellae are convected or are generated in situ, the capillary pressure increases up to a limiting capillary pressure as the gas fractional flow is raised. With further increase in gas fractional flow, the capillary pressure remains at its limiting value while the foam texture becomes coarser. The limiting capillary pressure for foams in porous media should vary with more than just surfactant formulation: gas velocity and the permeability of the medium can also be expected to be important variables. SPERE P. 919
HSE Horizons - This is a condensed version of paper SPE 73853, which was presented at the SPE International Conference on Health, Safety, and Environment in Oil and Gas E&P held in Kuala Lumpur, Malaysia, 20-22 March 2002.
TX 75083-3836, U.S.A., fax 01-972-952-9435. Abstract Produced Water Volumes
Mechanisms of reservoir souring are reviewed in general. A survey was conducted on several seawater and source-water floods to determine the factors that could be responsible for reservoir souring. Data from Shell's offshore Gulf of Mexico field (Cognac Platform) were analyzed more closely, and the results are presented as a case history. All seawater floods examined in the survey were found to be soured to varying degrees. The main factors responsible for the souring of seawater floods appear to be the sulfate ion concentration, the organic acid content, and the salinity of the produced water. The role of sulfate-reducing bacteria in souring of several Shell waterfloods is discussed. Introduction Many offshore fields require pressure maintenance in order to recover oil and gas reserves. Often there are no source-water sands available, and seawater is the only available injection water. Formation souring with the injection of relatively low salinity and high sulfate content brines, such as seawater, has been observed at some time during the producing life of the field. The number of sour wells within a field is variable; some wells are noticeably sour (up to 100 ppm of H2S in the produced gas), while others remain free of H2S. This souring is generally attributed to sulfate-reducing bacteria (SRB) activity. It is difficult to keep any injection system sterile as well as maintain bacteria-free operations during well drilling and completion. The main goals of this investigation wereTo initiate an industry survey of seawater floods in the Gulf of Mexico, Alaska, and California,To identify factors that could cause formation souring,To develop a methodology to predict the likelihood and magnitude of H2S generation, andTo outline the field and research studies necessary to understand reservoir souring mechanisms. Incentives to understand reservoir souring include (1) predictions that would impact the facilities and downhole tubing design and material selection and, perhaps, the oil value of future deepwater developments, and (2) knowledge on how to control, chemically or biologically, the extent of sour gas production in sweet reservoirs for reducing potential equipment and pipe corrosion failures, formation plugging, and environmental and human health hazards. Goals 1,2, and 4 were achieved. However, due to the limited data, the development of a method to predict the magnitude of H2S generation was not possible. This paper presents the current understanding of reservoir souring mechanisms and an analysis of survey data that were compiled on seawater floods and selected source-water floods. Data from SOI's Cognac flood were reviewed more closely, and the results are presented as a case history. A general review of field experience on the role of SRB in souring Shell waterfloods is also presented. MECHANISMS OF RESERVOIR SOURING The following section is a summary of the current proposed mechanisms of reservoir souring. The microbial and abiotic geochemical mechanisms are discussed.Microbial sulfate ion (SO4=) or sulfur (S) reduction. It is well known that the SRB are a physiologically diverse and ubiquitous group of anaerobic bacteria capable of reducing so: to H2S when grown on several "oxygen-containing" substrates such as short-chain volatile acids (formic, acetic, propionic, and butyric), lactic acid, phenols, and benzoates. Volatile fatty acids are present in many oilfield produced waters, and they may be a predominant factor in the growth of sulfate-reducers in oil reservoirs and the sour gas formation during waterflooding for enhanced recovery. P. 449^
Solid particles in injection water build up a filter cake when intercepted on the face of the formation matrix, in the perforations, or even in the gravel pack. The effect of applied pressure, solids type, and oil presence on the porosity and permeability of these thin cakes was determined using a compression–permeability cell. The solids investigated were iron sulfide, iron hydroxide, iron hydroxide/bentonite mixture, calcium carbonate, calcium sulfate, and produced silt and clay. Empirical correlations between permeability and porosity were determined and used to predict injectivity decline rate under reservoir conditions for four common well completions. A new model for calculating the combined matrix and filter cake resistances in perforations and fractures was developed by using the electrical circuit analog theory. The results of this study and an earlier study1 were implemented in a user-friendly PC program. This program predicts matrix damage and the injectivity decline rate as a function of solids properties. Consequently, filtration requirements and/or well stimulation schedules can be determined.
Many producing assets in the world have reached the so-called mature phase of development. Some of these assets have been producing for 30 to 40 years or more, which is typically beyond the design life, and have reached a water to oil ratio of 3 to 9 or more. There are many issues that affect the productivity and economic viability of these fields. Some of the challenges include integrity uncertainty in the wells, flow lines, and facilities; production bottlenecks due to the shift in gas, oil and water ratios; erosion/ corrosion; increased sand production and handling costs; high chemical consumption and treatment costs; and obsolete monitoring and control systems that are incompatible with new technologies and which contribute to the need for a large number of operations staff. Generally operators are faced with the commercial decision whether to sell the asset to a low cost operator, reinvest in the asset, or incur the cost of decommissioning.While the number and complexity of these challenges are significant, there are nevertheless a number of viable options for extending the economic life of such assets. Hydrocarbon recovery and production from these fields can be enhanced by infill drilling; acid and fracture stimulation; by implementing a range of remediation techniques such as recompletion with smart systems to reduce water and solids influx to surface facilities; and by the implementation of improved and enhanced recovery methods. Selecting the optimal strategy requires a holistic perspective on subsurface issues, wells, and surface facilities, and an ability to make projections of integrated performance. This is greatly facilitated by first developing a root cause understanding of the reservoir and production fluid characteristics, and second, the use of analysis tools that allow quick and reasonably accurate assessment of options.In order to increase value from matured fields, the goal is to increase oil recovery from the historical average of 35% and to optimize production by improving the operational efficiency. To achieve this goal, in this paper we will put forward two key imperatives that extend the life of a mature field: (1) Finding and accessing the by-passed oil and (2) Maintaining High uptime during Asset production and operation.In this paper, several mature fields in Europe, Far East and Middle East are analyzed and presented in order to: -highlight the root causes for either low production and or higher operating costs; -assess the impact of both surface and subsurface uncertainties in multiple development planning scenarios; -develop the best strategies and options for improved reservoir, well and facilities management; -demonstrate the contributions of implemented new technologies that optimized performance of artificial lift, minimized downtime by well intervention and reduced operational costs by fluids flow assurance in well and surface facilities; and -list the technical and economical challenges that still face the industry.
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