Ammonia is logistically preferred over sodium carbonate for alkaline/surfactant/polymer (ASP) enhanced-oil-recovery projects because of its low molar mass and the possibility for it to be delivered as a liquid. On an offshore platform, space and weight savings can be the determining factor in deciding whether an ASP project is feasible. Logistics may also be critical in determining the economic feasibility of projects in remote locations.Ammonia as alkali together with a surfactant blend of alkyl propoxy sulfate/internal olefin sulfonate (APS/IOS) functions as an effective alkali. Surfactant adsorption is low, and oil recovery in corefloods is high. Static adsorption tests show that low surfactant adsorption is attained at pH >9, a condition that ammonia satisfies at low solution concentration.It is expected that ammonia has a performance deficiency relative to sodium carbonate in that it does not precipitate calcium from solution. Calcium accumulation in the ammonia ASP solution will occur, caused by ion exchange from clays. The high oil recovery for ammonia and the calcium accumulation in ASP and surfactant/polymer corefloods with APS/IOS blends show that this surfactant system is effective and calcium-tolerant. Also, phase behavior and interfacial-tension (IFT) measurements suggest that APS/IOS blends remain effective in the presence of calcium. Ethylene oxide/propylene oxide sulfates (such as the used APS) are known commercially available, calcium-tolerant surfactants. However, because of hydrolysis, sulfate-type surfactants are suitable for use only in lower-temperature reservoirs.Very different behavior was noticed for phase-behavior measurements with calcium-intolerant surfactants such as alkyl benzene sulfonates and IOS. In this case, calcium addition results in a very high IFT and complete separation of oil and brine. Presumably, this will result in low oil recovery. A preferred approach for ASP offshore with divalent-ion-intolerant surfactants may be the use of a hybrid alkali system combining the attributes of sodium carbonate and ammonia. The concept is to supply the bulk of the alkalinity for an ASP flood by ammonia with all the inherent logistical advantages. A minor quantity of sodium carbonate is added to the formulation to specifically precipitate calcium ions.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe industry has developed standard methods to effectively evaluate the propping agents used in hydraulic fracturing operations. The understanding gained from the consistant application of the methods has greatly helped to optimize productivity.of hydraulicly fractured wells.This paper presents two mechanisms that may significantly increase the understanding of how to optimize fracture conductivity to sustain productivity. The standard methods use well "aged" (passive) proppant and simulated formation materials; whereas, in practice, formation faces are highly activated as an immediate result of mechanical fracturing, as is a significant portion of the pumped proppant.The chemistry that occurs at freshly exposed mineral surfaces is different than that of the aged surfaces used in the laboratory. For example, condensation of polymers on freshly generated surfaces may result in polymer chains becoming anchored to the surface. This anchoring prevents some polymer from being removed by normal gel-breaking mechanisms and forms points of attraction for the collection of broken polymer and fines debris, leading to significant permeability damage and reduced fluid recovery.After a treatment when pressure is relieved and well clean-up begins, temperature and stress gradients are high; significant crushing of proppant and formation material may occur as a packed fracture moves toward an equilibrium condition. The presence of hHigh-ionic-strength fracturing fluids, particularly at high pH, may promote a rapid mineral diagenesis-type reaction that leads to proppant compaction, embedment, and crystalline overgrowth permeability damage.This paper provides laboratory and field data supporting the conclusion that the application of a thin, highly dielectric, polymer film to coat proppant can result in a long-term reduction in mineral dissolution rate, compaction, embedment, and polymer anchoring sites. Field data shows this effect has a dramatic improvement in fracturing fluid recovery and well productivity.

Summary Rapid loss of fracture conductivity after hydraulic fracture stimulation has often been attributed to the migration of formation fines into the proppant pack or the generation of fines derived from proppant crushing. Generation of crystalline and amorphous porosity-filling minerals can occur within the proppant pack because of chemical compositional differences between the proppant and the formation, and the compaction of the proppant bed because of proppant pressure solution reactions. Findings presented in this paper suggest that diagenesis-type reactions that can occur between proppant and freshly fractured rock surfaces can lead to rapid loss of proppant-pack porosity and loss of conductivity. Introduction Lehman et al. (2003) reported that the use of surface-modification agents (SMA) to coat proppants used in propping hydraulic fractures resulted in sustained and more uniform production from wells. Fig. 1, taken from that publication, shows the production decline curves from some of their data, and it does appear to show a significant change in decline rate compared to the use of untreated proppant. This SMA was described as a nonhardening resin that is insoluble in water and oil. It is supplied in a solvent that is quickly extracted once it is introduced to aqueous-based frac fluids, leaving a tacky, hydrophobic coating on the proppant. Initial use of this type of SMA treatment (Dewprashad et al. 1999; Nguyen et al. 1998a, b) was promoted as a method to increase the conductivity of proppant owing to its capability to prevent close packing of the proppant, which can result in increased porosity and permeability of the pack, by rendering the proppant surface tacky. Subsequent studies indicated that its use provided proppant-pack protection from fines infiltration and migration. This mechanism has been employed to explain the observations that sustained production results from the use of SMA on proppants. This is further substantiated by long-term results obtained in a single field study known for fines production problems. That both mechanisms are active has been well established through laboratory studies, but they alone do not completely explain the reduction in production decline rate as reported. A field study of SMA-treated proppant was reported to the Arkansas Oil and Gas Commission 2004 CBM Workshop that disclosed long-term results on gas production. These were CBM wells in the San Juan basin that typically required refracturing each year to produce at an economical rate. With the SMA-treated proppant, no refracs have been required, and as shown in Fig. 2, production has remained essentially constant for 5 to 6 years. This longevity was initially attributed to prevention of fines invasion into the proppant pack; however, it is possible that there are additional mechanisms operational.

High Pressure Air Injection (HPAI) is a potentially attractive enhanced oil recovery method for deep, high-pressure light oil reservoirs after waterflooding. The advantage of air over other injectants, like hydrocarbon gas, carbon dioxide, nitrogen, or flue gas, is its availability at any location. HPAI has been successfully applied in the Williston Basin for more than twenty years and is currently being considered by many operators for application in their assets.Evaluation of the applicability of HPAI requires conducting laboratory experiments under reservoir temperature and pressure conditions to confirm crude auto-ignition and to assess the burn characteristics of the crude/reservoir rock system. The ensuing estimation of the potential incremental recovery from the application of HPAI in the reservoir under consideration requires fit-for-purpose numerical modeling. Typically, the flue gas generated in-situ by combustion leads to in an immiscible gas drive, where the stripping of volatile components is a key recovery mechanism. HPAI has therefore, in some instances, been modeled as an isothermal flue gas drive, employing an Equation of State (EOS) methodology. This approach, however, neglects combustion and its effects on both displacement and sweep. Furthermore, the EOS approach cannot predict if, and when, oxygen breakthrough at producers occurs. Combustion can be included in a limited fashion in simulations at the expense of extra computational time and complexity. In the available literature, combustion is taken generally into account under quite simplified conditions. This paper addresses the role that combustion plays on the incremental recovery of HPAI. Numerical simulations were conducted in a 3D model with real geological features. In order to capture more realistically the physics of the combustion front, a reservoir simulator with dynamic gridding capabilities was used. Kinetic parameters were based on the combustion tube laboratory experiments. The impact of combustion on residual oil, sweep efficiency and predicted project lifetime is presented by comparing isothermal EOS-simulations and multi-component combustion runs.

This paper describes a series of experiments that used X-ray computer tomography (CT) to visualize the mobilization of remaining oil by Alkaline Surfactant (AS) and Alkaline Surfactant Polymer (ASP) flooding after conventional waterflooding. The experiments were conducted in cores drilled from Gildehauser and Bentheimer sandstone outcrop material with diameters of approximately 7.55 cm and lengths of approximately 27 cm and one meter. Crude oil with in-situ viscosities of 1.3, 2.3 and 100 cP was used in the experiments. The changes in the fluid saturation distributions with time obtained with X-ray computer tomography are subsequently used to improve the conceptual understanding of the ASP process. In addition to pressure and effluent data collected during conventional core flood experiments, phase and saturation distributions in space and time are needed to more completely interpret the results of core floods. This additional information reveals underlying mechanisms, and assists the development of models that capture the physics of ASP that can ultimately be used to provide field scale predictions for ASP performance. One important observation from the experiments is that there exist a consistent fingering pattern in the zone upstream of the oil bank. Although fingering is often considered a bad sign for a displacement process the experiments also demonstrate that the fingering zone is contained in the area upstream of the oil bank and that the velocity of the front of the oil bank is significantly greater than that of the fingering zone. The production following the clean oil bank (tail) observed in many ASP core floods is a consequence of the formation of this fingering zone. Effluent analyses conducted on the produced fluids from the long core experiments showed a sharp, rapid build up in polymer viscosity that coincides with the beginning of the tail production while the surfactant concentration only gradually increases to its injection value during the tail production. Another important observation is that a characteristic self-similar cross-sectional averaged oil saturation profile develops during ASP injection after water flood in cores containing reactive crude oil with 100 cP viscosity and in non reactive light crude oil. The implications of the self-similarity of the saturation profiles in combination with the observation that the surfactant propagation is retarded with respect to the polymer propagation results in a polymer flood ahead of the ASP-slug and a corresponding characteristic oil production profile. The characteristics of this process can be captured with an extended fractional flow approach that utilizes three fractional flow curves: one for the ASP-slug, one for polymer, and the original fractional flow curve for oil-water.