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Collaborating Authors
Zaitoun, A.
Water Shutoff in Fractured Carbonate Vertical and Horizontal Wells by Bullhead Chemical Injection: A Success Story
Al Mufargi, H. (Daleel Petroleum LLC, Muscat, Oman) | Al Harthi, H. (Daleel Petroleum LLC, Muscat, Oman) | Al Naabi, A. (Daleel Petroleum LLC, Muscat, Oman) | Al Shuelly, M. (Daleel Petroleum LLC, Muscat, Oman) | Al Rawahi, M. (Daleel Petroleum LLC, Muscat, Oman) | Al Abri, M. (Daleel Petroleum LLC, Muscat, Oman) | Al Farsi, M. (Daleel Petroleum LLC, Muscat, Oman) | Al Rashdi, M. (Daleel Petroleum LLC, Muscat, Oman) | Al Harrasi, M. (Daleel Petroleum LLC, Muscat, Oman) | Al Mandhari, A. (Daleel Petroleum LLC, Muscat, Oman) | Hernando, L. (Poweltec, Rueil-Malmaison, France) | Martin, N. (Poweltec, Rueil-Malmaison, France) | Salehi, N. (Poweltec, Rueil-Malmaison, France) | Bouillot, J. (Poweltec, Rueil-Malmaison, France) | Templier, A. (Poweltec, Rueil-Malmaison, France) | Omonte, G. (Poweltec, Rueil-Malmaison, France) | Zaitoun, A. (Poweltec, Rueil-Malmaison, France)
Abstract Many wells in GCC (Gulf Cooperation Council) are producing from fractured carbonate reservoirs under aquifer or water injection pressure support. After water breakthrough, these wells suffer from high water cut production and low oil production caused by water channeling. An original technology using combination of microgel and gel was successfully implemented in an open hole fractured horizontal well under aquifer support (SPE 203394). This technology enables bullhead injection while minimizing the risk of damage. The treated well almost doubled oil production rate for one year along with a drop in the water cut from 92% to 80%. Three new campaigns of Water Shutoff treatments were performed in 2 years, using the same technology in the same type of reservoir. The treatment consisted of microgel injection, followed by gel, followed by microgel again. These sequences enable protecting the matrix from gelant leak-off and keeping open the fracture network surrounding the wellbore once the gel is in place. The total volume of treatment was around 250 m3. The size of the different slugs was adjusted according to well characteristics (open interval, flow rate, etc.). Diagnostic prior to the treatment using WOR Chan plots helped to identify the wells suffering from strong channeling. All chemicals were injected in bullhead mode. Most injections were performed through the annulus without pulling out of the hole the tubing string BP and ESP pump. Injection rate was between 1 and 3 BPM. Over the 11 wells submitted to the WSO treatments (two vertical and nine horizontal producers), four responded very positively, showing a sustainable additional oil production over time, five responded positively for several months, and three did not respond markedly. After treatment, for all the wells, the gross production could be maintained resulting in extra oil production along with water cut reduction. No well has been damaged by the treatment confirming the validity of the low-risk approach of this chemical injection strategy. After continuous surveillance of each treated well, from decline curves analysis and cumulative oil vs. cumulative water plots, the additional oil production is estimated as 165,000 bbl by end of Dec 2022, and keeps growing with time. This result has been obtained with mature wells that were producing with very high water cut (between 86 and 100%) before the treatment. The water shutoff technology combining microgel and gel can be applied in many reservoirs suffering from water channeling through fractures. This technology is low risk and can be used either in horizontal and vertical wells. Chemical injection proceeds rigless and bullhead, thus at low cost, and showed efficiency in very high water cut wells, inducing production of large quantity of additional oil in a mature field.
- Asia > Middle East > UAE (0.49)
- Asia > Middle East > Oman (0.48)
Rheology and Transport in Porous Media of New Water Shutoff / Conformance Control Microgels
Rousseau, D. (Institut Français du Petrole) | Chauveteau, G. (Institut Français du Petrole) | Renard, M. (Institut Français du Petrole) | Tabary, R. (Institut Français du Petrole) | Zaitoun, A. (Institut Français du Petrole) | Mallo, P. (SEPPIC) | Braun, O. (SEPPIC) | Omari, A. (LMDA-ISTAB, Bordeaux U.)
Abstract The performances of new microgels specifically designed for water shutoff and conformance control were extensively investigated at laboratory scale. These microgels are preformed, stable, fully water soluble, size controlled with a narrow size distribution, and non-toxic. They reduce water permeability by forming adsorbed layers soft enough to be very easily collapsed by oil-water capillary pressure, so that oil permeability is not significantly affected. Since the manufacturing process of these new microgels make possible to vary chemical composition, size and crosslink density, they can be designed as desired to meet the requirements of a given field application. The laboratory results reported in this paper concerns mainly three microgel samples having significantly different crosslink densities. We describe the relevant laboratory methods used to determine main microgel characteristics. The microgels have remarkable mechanical, chemical and thermal stability. Their behavior in porous media have been investigated extensively, showing that:their propagation distance is only limited by the volume injected, their injectivity is facilitated by a shear-thinning behavior and water permeability reduction can be achieved as desired by controlling the thickness of adsorbed layer. Thus, this new microgels, now available at industrial scale, look as very promising tools, not only for water shutoff but also for conformance control in heterogeneous reservoirs. Introduction Background In a global context of growing energy needs with a perspective of depletion of oil and gas resources, extending the life of hydrocarbon reservoirs is a real challenge for the decades to come. In that situation, as well as for environmental reasons, reducing significantly water production and improving oil recovery efficiency is an important goal for oil industry. Thus the development of more reliable techniques using "green" products for water-shutoff, conformance, and mobility control is of crucial interest. Among the methods available to reduce water production [1], injecting a gelling system composed of a polymer and a crosslinker has been widely used [2–5]. In this process, the gel is formed in-situ. Since gelling properties have been found to depend on many factors [6–11], the gelling time, the final gel strength and also the depth of the gel penetration is quite difficult to predict. This difficulty results from the uncertainties concerning different factors: shear stresses both in surface facilities and in near-wellbore area and also physico-chemical environment around the well (pH, salinity and temperature). Moreover, both polymer and/or crosslinker adsorption in the near-wellbore region and dilution by dispersion during the placement can affect the effectiveness of the treatment. To overcome these severe drawbacks, different authors have recently proposed new methods, aimed at improving the process by injecting preformed gels particles or dilute gelling systems. Bai et al. method [12,13] consists in drying, crushing and sieving polymeric gels prior to injecting them. Mack et al. [14,15] method consists in obtaining "colloidal dispersion gels" (CDG) by crosslinking low concentration polymer solutions with low amounts of chromium acetate or aluminium citrate. This process slows down the gelation kinetics, so that, on a well injection time scale, those systems only form separate gel bundles, thus making possible to enter the matrix rock. However, the in-depth propagation of these two of gels remains questionable. In 1999, Chauveteau et al. introduced [16] a completely new concept which consists of injecting fully water soluble, non-toxic, soft, stable and size-controlled microgels into the reservoir. A first type of microgels, using an environmentally friendly zirconium crosslinker, has been extensively studied in the past years, regarding both the understanding of gelation mechanisms and the transport properties in porous media [16–23]. More recently, a second type of microgels, which are covalently crosslinked, was introduced [24]. These microgels, now available at industrial scale, have been shown to have very attractive properties for both water shutoff and conformance control operations.
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Yian Formation (0.99)
- Asia > China > Heilongjiang > Songliao Basin > Daqing Field > Mingshui Formation (0.99)
Abstract The oil industry is currently facing severe restrictions concerning the discharge of oilfield chemicals into the environment. For most of the actual widely used mineral scale inhibitors, the future will depend on the possibility of their re-injection into disposal wells. Another alternative could be the deployment of biodegradable chemicals. For this purpose a new class of "green" scale inhibitors, the Carboxy Methyl Inulins (CMI), has been evaluated in its ability to prevent carbonate and sulfate scale deposition by squeeze treatments. Jar Tests and Tube Blocking Tests, performed on actual reconstructed injection and production waters show that the CMI inhibitors exhibit competitive inhibiting performances compared to currently used scale inhibitors. Core tests for the determination of CMI adsorption / desorption properties in static and dynamic conditions help to predict inhibitor squeeze lifetime and to design its implementation in future squeeze applications. It is finally concluded that the Carboxy Methyl Inulins may already be considered as viable alternate mineral scale inhibitors to currently used but not biodegradable chemicals. Introduction The discharge into the environment of oil-field chemicals becomes more and more scrutinized and legislated. The oil offshore industry is particularly concerned by the severe restrictive regulations concerning the environmental impact of the products used. In the field of the mineral scale inhibition, chemicals are usually squeezed directly into the reservoir section surrounding the production well and back produced with the formation fluids. The only alternative for the produced water seems to lie between the re-injection on site or the use for the squeeze treatment of biodegradable chemicals. Poly (amino-acids) and in particular polyaspartates have recently been evaluated as environmental safe "green" mineral scale and corrosion inhibitors. They have been also field tested in down-hole squeeze operations. In the present paper a new class of biodegradable chemicals, the Carboxy Methyl Inulins (CMI), has been evaluated in its ability to prevent carbonate and sulfate scale deposition during topside or squeeze treatments. Their efficiency as scale inhibitors has been checked comparatively to that of the currently used phosphonates or polyacrylates by conducting Jar tests and Tube blocking tests. Their possible application in squeeze operations has been investigated by performing adsorption/desorption measurements on model limestones in static and dynamic conditions. In particular the influence of the composition of the production brine, used in the desorption step of the core-flood experiment, on the inhibitor return concentration was investigated. An experiment using Sea water as production brine was compared to an experiment using Forties water, which has a higher TDS and in particular a higher calcium content. These tests seek to establish an evaluation of two different products but of very comparable structure. We tested the CMI and the polyacrylate. Both are polymers with carboxylic groups but with a very different structure of their polymeric chains. Products. Carboxy Methyl Inulins (CMI) are derivatives from Inulin. Inulin is a natural ß (2–1) polyfructoside with a glucose unit at the reducing end. It is extracted from Chicory roots and used mainly in food applications. Carboxylate groups are introduced into the polysaccharide by carboxymethylation with Sodium monochloro acetate as reagent in alkaline medium (Figure 1). Carboxymethyl Inulin is made at different degrees of substitution (DS:average amount of carboxymethyl groups / monosaccharide unit) and products are commercially available with a DS of 1.5, 2.0 and 2.5. The average degree of polymerization (DP) of the commercial product is DP=10.
- Europe (1.00)
- North America > United States > Texas (0.93)
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock (0.36)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (1.00)
- Materials > Chemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Europe > United Kingdom > North Sea > Central North Sea > Forties Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 21/10 > Forties Field > Forties Formation (0.99)
Abstract In previous papers we investigated high-molecular-weight polyacrylamide adsorption under high shear rates in low-permeability media and found that, above a critical value ?c, adsorbed macromolecules can reduce the permeability by factors over hundred, suggesting a mechanism of pore throat bridging. New lab experiments have been designed specifically to elucidate the mechanism at the origin of this "bridging adsorption". Polymer injections were carried out over a wide range of shear rates in homogeneous high-permeability granular packs having hydrodynamic pore throats too large to be bridged by polymer macromolecules. When polymer is injected at low shear rate (??c), eH increases slowly up to reach maximum values eHM increasing with injection shear rate. These eHM values were found to be large enough to explain the very high reductions in permeability obtained previously in low-permeability packs. These results show that polymer adsorption in porous media can be increased significantly by the hydrodynamic forces normal to the pore wall, as soon as they become high enough to "push" additional macromolecules into the already adsorbed polymer layer. This mechanism increases both polymer adsorption density and adsorbed layer thickness. We propose to refer to this mechanism as a "flow-induced adsorption". This new interpretation is consistent with all results previously attributed to "bridging adsorption" and the new results reported in this paper. It provides an important conceptual tool to model polymer placement in water shutoff and to design conformance treatment. Introduction In a series of previous papers, several experimental results were presented, dealing with polymer behavior in porous media under near-wellbore flow conditions. These experiments showed that, when a large number of pore volume is injected in low-to-medium permeability cores beyond a critical shear rate ?c, a plugging tendency is observed as well as a strong increase in adsorption density. The plugging does not occur either in non-adsorbing conditions or in high permeability cores. To explain these observations, a mechanism called "bridging adsorption" was proposed, consisting of two steps:the stretching of macromolecules by high elongation stresses and the adsorption of these stretched macromolecules by forming numerous bridges accross pore throats. Such a mechanism is consistent with several observations such as:A rate of plugging increasing as permeability decreases. A rate of plugging increasing with the presence of residual oil (which reduces pore throat size). A rate of plugging increasing with adsorption energy (from neutral to cationic polyacrylamides). A rate of plugging decreasing in cores having a broad pore size distribution. However, such a mechanism did not fit very well with some other results, namely:The critical shear rate (around 70 s) is significantly lower than the onset of coil-stretch transition (> 200 s). The fact that more than 99% of polymer could flow easily (with very small apparent viscosity) through highly bridged pore throats. The fact that oil could also flow easily with a very low resistance factor, through these strongly plugged cores. These discrepancies with the proposed mechanism of "bridging adsorption" called for additionnal experiments. We decided to run the same type of coreflood experiments as before in cores with very high permeability, for which pore throat size was too large to allow polymer bridging, even with strongly stretched macromolecules. The experimental procedure was designed to measure very precisely the evolution of the thickness of the adsorbed polymer layer after each polymer slug.
Abstract The presence of hydrosoluble polymer or gel in porous media induces a selective reduction of permeability -called Disproportionate Permeability Reduction, DPR- i. e. a reduction of relative permeability to water much larger than the relative permeability to oil. Several experimental studies have been focused on oil/water systems with different cores, polymers and wettability conditions, confirming the DPR effect. The goal of our study is to investigate polymer effect on gas/water permeability in a wide range of flow rate, reproducing near well-bore conditions in water shutoff applications. The experimental study presented here proceeds to water and nitrogen injections into sandstone cores before and after polyacrylamide adsorption. Both low-rate Darcy regime and high-rate non-Darcy regime were investigated during gas flow, the later one being modeled using the classical Darcy-Forchheimer formalism. In the Darcy regime, the DPR effect induced by polymer adsorption is more significant when observed on gas/water systems than on oil/water systems investigated under comparable conditions during previous studies. Polymer induces both a strong reduction of the relative permeability to water while affecting very little the relative permeability to gas, and a significant increase of the irreducible water saturation. In the non-Darcy regime, taking into account water saturation and permeability modifications, we observe a reduction of inertial effects when gas is injected after polymer. Experimental data are discussed and confronted with the different hypotheses put forth to explain DPR. Both DPR effect and the reduction of inertial resistance coefficients during gas flow may have important applications in gas well treatments. Introduction Gas flow in porous media is a subject of central importance for many applications ranging from Improved Oil Recovery processes based on gas injection to underground temporary gas storage in depleted reservoirs or natural aquifers. A major problem encountered by reservoir engineers during field operations lies in the excessive water production that may cause early well abandonment. This excessive water production is generally due to the effect of natural heterogeneities, fractures or viscous fingering causing channeling of water and leading to high water cut. Among others, a widely used technique to reduce the water cut consists of polymer or gel injection in producing wells in order to reduce water permeability. Although the physical explanation of the selective effect is still a matter of controversy, the presence of polymer or gel in porous media leads indeed to a selective reduction of permeability, known as "Disproportionate Permeability Reduction" (DPR). Almost all experimental results on oil/water systems reported in the literature show that, after polymer injection, relative permeability to water is more reduced than relative permeability to oil. Some experimental results, also available for gas/water systems, indicate the same behavior and show that water relative permeability is strongly reduced while relative permeability to gas is only slightly affected. A large amount of literature has been dedicated to the DPR mechanism, including, for instance, the role of polymer, core and wettability conditions. Despite or due to all these results, different physical mechanisms have been put forth to explain the origin of DPR. To summarize, they can be classified as follows:Fluid partitioning. This scenario considers that oil and water flow in separate pore networks determined by the pore size distribution and that water-based polymer or gel affect the water network only. To our opinion, this interpretation is unsufficient to explain DPR since this effect occurs over the whole range of saturation during unsteady state two-phase displacement for which a dynamic configuration of oil and water paths must be considered.
- North America > United States > Oklahoma (0.29)
- North America > United States > Texas (0.29)
- Research Report > New Finding (0.68)
- Research Report > Experimental Study (0.54)
Abstract A polymer treatment has been successfully applied in a Gaz-de-France gas storage well facing excessive water production problems limiting its maximum gas flow rate. The well was located in a limestone reservoir submitted to an active bottom aquifer. To reduce the risk of well impairment while enhancing the efficiency to fight water coning, the polymer slug was injected into the half of the open interval located at the bottom of the reservoir. A study consisting of laboratory core tests and numerical simulations aimed at sizing polymer slug and concentration before performing the treatment. The level of water permeability reduction to reach was fulfilled with single polymer adsorption without the need of adding cross-linker. After a period of two years where no significant effect on water production occurred, the well progressively improved its performances while water production remained at the same level in neighbour wells. After ten years of survey, the well, which was one of the worse of the storage, became one of the best, capable to sustain high levels of gas production with low water. The delay in well response is probably due to the high water saturation level of the reservoir surrounding the wellbore consecutive to the injection of the polymer slug. The results show that the technique, while easy to handle, gives remarkably efficient long-lasting effect. Introduction Polymer/gels have been successfully used as water shutoff agents for production well treatments. A typical treatment consists of preparing a polymer solution in surface tanks, which is then pumped downhole and squeezed into the formation up to a distance of several meters. A crosslinker is often added to the polymer solution to increase gel strength. Whenever possible, mechanical tools (coil tubing, retrievable packers) are used to isolate the zone to be treated from the rest of the open interval in order to reduce the risk of well damage. Since water encroachment often occurs through high-permeability streaks, placing the gel in the right zone becomes a major issue for treatment success. However, in many cases, the gel has to be pumped into the whole producing interval, which enhances strongly the risk of well damage. This occurs in different situations such as:poor identification of water zones excessive cost of workover unsuitable completion (gravel pack, open hole, etc.) In such cases, to reduce the risk of well damage, the treatment consists of single polymer or weak gel treatment. The mechanism by which the treatment works is called "Relative Permeability Modification" (RPM) or "Disproportionate Permeability Reduction" (DPR). Once the polymer/gel is adsorbed on the surface of the rock, it reduces selectively the relative permeability to water krw with respect to the relative permeability to oil kro or to gas krg. The origin of this unique property is still controversial. However it is well documented in the literature and has been observed with most water-soluble polymer/gel systems and rock materials. Liang et al. have shown that DPR property of gels does not garantee treatment success, but that gel placement around the wellbore still remains a major issue for "bullhead" treatments. The reason is that, for all layers invaded by the gel and producing oil with a fraction of water, the reduction of krw induces automatically a reduction of kro via an increase in water saturation. The productivity of pay zones is thus affected, even with a perfect DPR which does not reduce at all the relative permeability to oil or to gas. All these aspects show that water shutoff polymer/gel treatments are difficult to control, more especially "bullhead" treatments. A proper design has to take into account the mechanism of water production in the well and in the surrounding reservoir, the completion of the well, the selection of the chemicals and the optimization of the formulation, finally, the cost of the treatment to be compared to production forecasts.
Abstract Adsorption of water-soluble polymers in porous rocks is known to reduce water permeability much more than oil permeability. This effect is often referred to as "Disproportionate Permeability Reduction" (DPR) and can be used in production well treatment to reduce the water cut. This paper deals with nonionic polyacrylamide adsorption on carbonate rocks having different wettability properties. Cores were used first in their native water-wet condition, and after a wettability modification, which was obtained by aging cores saturated with a polar crude oil at 60°C for 6 weeks. Efficiency of the treatment was attested and quantified by strong changes in the wettability index as measured using Amott tests. Drainage and imbibition cycles were performed on these carbonate samples before and after polymer treatment. Polymer adsorption and oil/water relative permeabilities were compared for both media. While the quantity of adsorbed polymer is almost the same on water-wet and on wettability-modified cores, adsorption rates, estimated from viscosity profiles of effluents, are significantly different, suggesting that the polymer slowly restores part of the water-wet character of the native core. All our results indicate that polyacrylamide adsorbs on the rock whatever being the wetting conditions. While disproportionate permeability reduction is always observed, DPR is greater in low-permeability cores. Introduction. Excessive water production is a problem of central importance for field operators. High water cut can lead to stop production for economical reasons. Among the solutions proposed to circumvent this problem, direct injection of polymer in the surroundings of the wellbore has been shown to be an efficient one. Polymer or gel injections in producing wells are able to lower the water cut by selectively reducing water relative permeability of the rock with respect to oil relative permeability. From a physical point of view, adsorption of water-soluble polymer on pore walls is known to modify two-phase flow properties of a porous medium. Several mechanisms involved in the action of polymers or gels have been reported in the literature and put forth to explain what is often referred to as "Disproportionate Permeability Reduction" (DPR):Shrinking/swelling of polymer depending on phase flow (Menella et al.). A possible explanation lies in the fact that adsorbed polymer shrinks while oil flows, and swells in the presence of water. This mechanism is consistent with the fact that the stress applied on the polymer layer by the flow is strong enough to induce a significant deformation of the layer. However, more experimental work is required to confirm the evidence of this phenomenon. Segregated pathways. This hypothesis put forth by Liang et al., and more recently by Nilsson et al. suggests that water and oil are flowing in two different pore networks. Consequently, a hydrophilic polymer flowing preferentially through the water network is able to reduce water permeability much more than oil permeability. On this basis, polymer injection was performed into rocks having different wettability properties and Nilsson et al. found that DPR was greater for porous media of mixed-wettability, which is consistent with the fact that water and oil pathways are better separated in this case.
Abstract Recently, cationic polyacrylamides (CPAM) have been successfully applied in water shutoff treatments of oil and gas wells. These polymers adsorb strongly on reservoir rocks, building up an adsorbed layer of significant thickness. Moreover, under high rates, the coiled macromolecules stretch and can bridge large pore throats. This so-called bridging adsorption mechanism has been described previously for high-molecular-weight non-ionic polyacrylamides (PAM). CPAM rheology and retention behavior has been studied in unconsolidated SiC packs and in Berea sandstones in a permeability range 0.1–1 D with CPAM solutions having a cationicity between 0 and 50%. Due to the attraction between the positive charges carried by the polymer chain and the negative surface charges of the rock, both CPAM adsorption and bridging adsorption are higher than for PAM having the same molecular weight. A maximum adsorption is found around 10–15% cationicity. This maximum, observed both in SiC and in Berea, is due to the competition between adsorption energy and pore wall accessibility. Although the permeability to water drops considerably after CPAM bridging adsorption, the permeability to oil is remarkably preserved, which makes CPAM attractive for water shutoff applications. Introduction Operators of mature oil and gas fields are often faced with a high water production coming from a water source (aquifer) or resulting from water injection. Excessive water production generally causes economic and operational problems. It decreases oil production, results in large amounts of water that need to be disposed and gives extra costs related to oil/water separation, handling and lifting. Other problems include the increased tendency for the formation of emulsions, scale and corrosion. So a high water production decreases the economical lifetime of a well and there is a need to reduce it. Classically the following distinction is made regarding the treatments to be used to tackle the water problem. If water and hydrocarbon zones are clearly separated, a permanent barrier, which is placed in the water producing zone, should be applied (Treatment A). Cements, resins or strong gels can form these full-blocking systems. If hydrocarbon and water zones are not clearly distinguishable or there is a high level of crossflow between layers, the use of total shutoff is risky. In this case disproportionate permeability reducers (DPR's), usually polymer solutions or weak polymer gels should be applied. The aim is to reduce water flow selectively while not influencing oil flow (Treatment B). The working of DPR's is based on the fact that adsorption of hydrophilic polymers can strongly decrease the relative permeability to water while having little effect on the relative permeability to oil. Due to the increasing need for bullhead treatments (treatments without zonal isolation), oilfield operators have focused on self-selective systems (Treatment B). These systems can be bullheaded downhole, reducing selectively the permeability to water with respect to the permeability to oil or gas. Due to this property polymers or weak gels were thought to be magic products that could be used in all situations. The relatively low success rate of DPR bullhead treatments (literature reports around 40%) shows reality is less favorable. Hereunder we will discuss three reasons for this by using an example of a DPR treatment on a two-layer well with 1/10 permeability contrast (Figure 1). Here the high-permeability layer is swept first, either by an active aquifer or by water injection. The low-permeability layer is still producing at high oil cut, although water production from the high-permeability layer is overtaking its oil production.
Abstract. The Cañadon Perdido field (Argentina) is an old field first produced by depletion and recently by waterflood. The reservoir lies in continental fluviatile deposits. The oil viscosity is about 100 cp. The unfavorable water-oil mobility ratio makes the waterflood efficiency low. Thus a polymer solution injection was studied to improve the oil production, considering the favorable temperature and salinity. The preparation of a pilot and the estimation of the economical efficiency of the process are presented. The paper presents the tasks integrated in the study:Laboratory (selection of polymer, measurements of its characteristics inside and outside the reservoir rock). Geological and reservoir engineering modelling of the pilot zone, including geostatistical simulation. Design of the pilot surface facilities and estimation of costs of a field extension. The conclusions of the study are:A polymer solution is efficient to produce additional oil. The reservoir conditions allow to use polyacrylamide, the cheapest polymer. If confirmed by the pilot results, polymer injection could be economically attractive. The reservoir is composed of sandy-silty- INTRODUCTION shally facies representing the Yacimiento El Trebol formation (upper part of Bajo Barreal Though polymer flooding was formation) and corresponding to a fluvial contemplated as a promising Improved Oil environment. The Tertiary transgressive Recovery (IOR) method in the late 70's and marine sediments of Salamanca formation are early 80's when oil price was high, it is sealing the continental series. presently not a widely applied recovery In the Cañadon Perdido field, five process. The present paper shows that, when stratigraphic layers have been identified. The reservoir conditions are favorable, polymer two uppermost, A and B constitute an upper injection is an economically attractive process. interval, well separated from a second group composed of C, D and E. The upper interval 1. PRESENTATION OF THE FIELD was first put into production in the 30's. The second deeper interval started producing in the The Cañadon Perdido field is located in 40's. the San Jorge basin, North East of the Province of Chubut, in Argentina, 25 km North of The reservoirs are found at a depth of Comodoro Rivadavia city. The field has been about 900 m below the ground surface. The operated by YPF since its discovery in 1928. structure is rather flat, and the series are The oil is rather heavy (22 °API and crossed by NW-SE faults. around 100 cp in reservoir conditions). The reservoir has been produced a long time by 1.2. Production history depletion, under dissolved gas drainage. A The upper interval (A, B) was initiall
- South America > Argentina > Chubut Province (1.00)
- North America > United States > Gulf of Mexico > Western GOM (1.00)
- North America > United States > Alabama > Escambia County (1.00)
- South America > Argentina > Patagonia > Golfo San Jorge Basin (0.99)
- South America > Argentina > Chubut > Golfo San Jorge Basin > Cañadon Perdido Field (0.99)
- South America > Argentina > Chubut > Golfo San Jorge Basin > El Trebol Field > D-129 Formation (0.98)
Abstract Low-molecular-weight polyacrylamides crosslinked with chromium(III) acetate are widely used in the oilfield industry to seal off watered out zones in matricial reservoirs. These products are usually mixed in surface facilities, then pumped down hole through coiled tubing and injected into the formation over a depth of several feet. For the operators, gelation time and gel consistency after well shut-in are the two most important parameters to control. The pumping time cannot exceed the gelation time and the maximum pressure drawdown sustainable by the gel is related to gel consistency (as measured, for instance, by the yield stress). Both are known to depend on temperature, polymer concentration and structure (molecular weight, hydrolysis degree), and crosslinker concentration. A systematic screening of these parameters has been undertaken by means of rheological measurements using a cone-and-plate rheometer. The procedure for determining gelation time consisted in monitoring the viscosity of the polymer and crosslinker solutions mixed at time t=0 and then submitted to shearing at a constant rate. The gelation time, which corresponds to a sudden rise in the viscosity, was observed to be independent of the applied shear rate but to strongly vary with temperature and, to a lesser extent, with polymer hydrolysis degree, concentration and molecular weight and crosslinker concentration. From the set of data obtained, simple correlations or rules of thumb for the gelation time variations are given, which can be used to optimize the formulation for a given field application. To evaluate gel consistency, some yield stress measurements were performed after a resting (shut-in) time of about 10 hours. The yield stress is related to the maximum drawdown sustainable by the gel in a formation through a simple relationship. Introduction The use of gels to seal off watered out layers has been increasing in recent years. The main advantages compared to cements area deeper penetration in the formation and an easy removal from the wellbore by water recirculation. However the control of the gelation process is often difficult due to the number of parameters affecting the process such as temperature, salinity, pH, polymer and crosslinker quality and concentration, making operational constraints delicate. Among the different systems, gels of partially hydrolyzed polyacrylamide crosslinked by chromium(III) acetate, hereafter referred to as PAMx (x is the hydrolysis degree or proportion of acrylate monomers in the polymer chain) and Ac3Cr, have been widely used recently. The system is fairly robust and overcomes the environmental restrictions of using chromium(VI)/reducing agent as a crosslinker. Two options are available. The first one, known under the trademark of MARCIT™, uses high-molecular-weight polyacrylamide and has been designed to treat fractured formations. The second one, known under the trademark of MARASEALT™, uses low-molecular-weight polyacrylamide and aims at sealing matricial formations.