Scleroglucan is a non-ionic exopolysaccharide produced by a specific fungi, called
The first part of this paper presents bulk experiments with this new EOR-grade scleroglucan. Filtration tests enabled to assess the efficiency of the dissolution process and the homogeneity of the solution. The dissolution method was optimized to obtain a proper solubilization of the polymer. Rheological behavior was also investigated, showing the high viscosifying power of the product, much higher than conventional EOR products like hydrolyzed polyacrylamide.
In a second part, coreflood experiments were performed in high-permeability (Kw(Sw=1)=1.5 D) Bentheimer sandstone and medium-permeability (Kw(Sw=1-So,r)=120 mD) Estaillade limestone. The main highlight is that no particular pre-filtration process was needed prior to injection in the core. Indeed, very good injectivities were obtained in both rock types. Dynamic adsorption was low in Bentheimer sandstone, and in Estaillade limestone in the presence of a residual oil saturation.
This study qualifies this new EOR-grade scleroglucan for EOR applications. With a good injectivity, low adsorption levels, high resistance to temperature and salinity, and low environmental footprint, this polymer could advantageously replace hydrolyzed polyacrylamide, and its derivatives, in hightemperature and high-salinity reservoirs, and in sensitive offshore areas.
Dupuis, Guillaume (SNF) | Antignard, Sebastien (SNF) | Giovannetti, Bruno (SNF) | Gaillard, Nicolas (SNF) | Jouenne, Stephane (Total) | Bourdarot, Gilles (Total) | Morel, Danielle (Total) | Zaitoun, Alain (Poweltec)
A great number of Middle East fields have too harsh reservoir conditions (high temperature, high salinity) for conventional EOR polymers used as mobility control agents. Traditional synthetic polymers such as partially hydrolyzed polyacrylamide (HPAM) are not thermally stable.
At temperatures above 70°C, acrylamide moieties hydrolyze to acrylate groups which ultimately may lead to precipitation and total loss of viscosifying power. Thermal stability can be improved by incorporating specific monomers such as ATBS or NVP. However, their polymerization reactivity can cause some compositional drift and limit their molecular weight / viscosifying power. Compared to HPAM, they will require a higher dosage and higher cost.
In this study, we present thermal stability and propagation behavior of a new class of synthetic polymers with high thermal stability. In harsh conditions of Middle East brines, with salinity ranging from sea water to 220 g/L TDS, they present excellent thermal stability until temperature as high as 140°C. Adsorption and mobility reduction were evaluated through coreflood experiments using carbonate cores and Clashach sandstone cores, with permeability ranging between 100mD and 700mD. Mobility and permeability reductions indicate a good propagation in both types of rocks.
The development of this new polymer is a major breakthrough to overcome the current limits of polymer EOR applications in harsh reservoir conditions. Moreover, molecular weights can be tailored from low to high molecular weights depending on reservoir permeability. Further work is needed to evaluate resistance to mechanical degradation, salt tolerance and adsorption in carbonates and sandstones.
Total has been operating oil and gas production from a series of heterogeneous carbonate reservoirs offshore Abu Dhabi since 1974. New technologies to increase oil recovery have been always tested and deployed on this field as tertiary gas injection since the 1990's or chemical EOR with a surfactant polymer pilot recently. On the same dynamic, we tested chemical water shut off treatment on two highly waterflooded wells with the injection of relative permeability modifiers (microgels).
This paper describes the full workflow followed for the pilot implementation and lessons learnt.
A particularity of this field is to produce in commingle oil from different thin reservoirs, with permeabilities ranging from to 0.5 to 50mD. Well production is combined through a single sliding sleeve, thus any mechanical shut off is impossible to block the water coming from the high permeability zones that is why the injection of RPM was considered.
Microgels were preferred over conventional polymers gels due to their higher resistance to salinity, shear, and H2S.
Laboratory studies were conducted to select the best microgel size and to obtain inputs for near well-bore model simulation (microgel adsorption, permeability reduction, injectivity). Numerical simulations were performed to predict the well responses and to define the optimal slug injection.
For this first pilot using microgels in high salinity environment, two vertical wells producing from two different reservoirs were tested, with watercut of 92 and 97%.
The microgel fluids were bullheaded into the whole perforated interval, the fluids were prepared on a nearby marine vessel; the operational challenges faced are detailed.
Preliminary results and way forward are described. The application of this microgel technology to high salinity and moderate temperature carbonate fields has a great potential to improve recovery in very mature fields at low cost.
SMG Microgels are pre-gelled polymers having a narrow size distribution and behaving like large polymer molecules. Their stability is strongly enhanced by internal cross-links. Several SMG microgels having different chemical compositions and cross-link density, with a size of around 2 μm were submited to laboratory corefloodtests. SMG propagation in reservoirs is driven by a size exclusion mechanism. Microgel size prevents invasion of low permeability zones and creates flow resistance in high permeability zones by adsorption on the rock. The permeability cutoff can be tuned by microgel size and chemistry. Permeability reduction generated by SMGs is determined by the thickness of the adsorbed layer which is roughly the size of the microgel in solution. It is little dependent of the adsorption level. Adsorption depends on the chemical composition of the microgel and on the nature of the rock.
An SMG Microgel with soft consistency was selected for a Conformance Control field application in a heterogeneous sandstone reservoir. Reservoir permeability ranges between 10 mD and 1200 mD with an average permeability of around 200 mD. The pattern consists of one injection well surrounded by eleven offset producers. The injection lasted 3 months with a total volume of 9,000 m3. After a few months, six offset producers showed increase in oil rate along with a reduction of a few points of water cut. One well lost both water and oil, thus proving diversion to the other wells. The trend remains steadily established in the pattern with continuous increase in additional oil production. After two years, more than 33,000 bbl of additional oil has been produced, giving a ratio of less than 0.7 lb of microgel per extra barrel of oil.
Al-Maamari, Rashid S. (Sultan Qaboos University) | Al-Hashmi, Abdulaziz (Sultan Qaboos University) | Al-Azri, Nasser (Petroleum Development Oman) | Al-Riyami, Omaira (Petroleum Development Oman) | Al-Mjeni, Rifaat (Petroleum Development Oman) | Dupuis, Guillaume (Poweltec) | Zaitoun, Alain (Poweltec)
A Polymer Flooding pilot trial has being implemented in a heavy oil field, in the South of Oman. A joint team composed of personnel from Sultan Qaboos University, Poweltec and Petroleum Development of Oman provided full laboratory support which included polymer products screening, and core-flooding experimental tests. The reservoir under investigation is a high-permeability sandstone with oil viscosity of around 500 mPa.s, brine salinity of around 5,000 ppm TDS and a subsurface temperature of 50°C. The reservoir characteristics are within the upper boundaries of known polymer flooding applications worldwide. This is further compounded by the presence of a strong bottom aquifer drive which requires the optimization of well placement.
Laboratory work consisted of both bulk and core-flood testing, in which different commercial hydrolyzed polyacrylamides were submitted to rheology, filtration and stability tests, from which one product was qualified. An intensive coreflood program was executed, consisting of rheology, adsorption and displacement experiments. Due to mild reservoir conditions (low salinity and temperature), the main focus was on filtration quality of the products. Following on from the filtration tests, coreflooding programs were implemented with very long sequence of polymer injection at a rate representative of polymer propagation in the reservoir.
Adsorption was found to be quite low (around 20 µg/g) for all the tested products. In-situ rheology was correlatable to the viscosity trends. The program of tests finally qualified a product with molecular weight of around 20 million Dalton. Above this level, long-term filtration becomes questionable with a slow but continuous ramp up of pressure noticeable after about 50 Pore Volumes.
This paper relates the successful water shut-off treatment of a heavy-oil Omani well combining the use of microgel and gel.
As many sandstone reservoir with strong aquifer in Southern Oman, this vertical well faced early water breakthrough along with sand production. Water cut increased dramatically until reaching 100%. The average permeability was around 500 mD but effective permeability ranged from milli Darcy to several Darcy. Due to well characteristics (several perforation intervals, gravel pack, etc…), it was not possible to identify and isolate the water production zones, which oriented the strategy towards the use of RPM products (Relative Permeability Modifiers). The treatment consisted of microgel and gel injections which were bullheaded into the whole open interval. After the treatment, the water cut dropped from 100% to 85% and sand production was stopped over a period of time superior to one year. The treatment was cost effective, producing more than 9000 bbl of extra oil in one year.
In this paper, we describe the treatment design methodology combining laboratory study and near wellbore simulations, and the optimization of injection sequences. Finally, the treatment execution is detailed followed by the presentation of the results obtained since the realization of the operations.
The results show that combining low-risk approach and low-cost RPM technology is an attractive way to restore productivity of watered out wells, in which conventional water shut-off zone isolation is not feasible.
The Pelican Lake heavy-oil field in northern Alberta (Canada) has had a remarkable history since its discovery in the early 1970s. Initial production by use of vertical wells was poor because of the thin (less than 5 m) reservoir formation and high oil viscosity (800–80,000-plus cp). The field began to reach its full potential with the introduction of horizontal drilling and was one of the first fields worldwide to be developed with horizontal wells. However, with primary recovery at less than 10% and 6.4 billion bbl of oil in place (OIP), the prize for enhanced oil recovery (EOR) is large. Initially, polymer flooding had not been considered as a viable EOR technology for Pelican Lake because of the high viscosity of the oil, until the idea came of combining it with horizontal wells.A first - unsuccessful - pilot was implemented in 1997, but the lessons drawn from that failure were learned and a second pilot was met with success in 2006. The response to polymer injection in this pilot was excellent, with oil rate increasing from 43 BOPD to more than 700 BOPD and remaining high for more than 6 years; the water cut has generally remained at less than 60%. Incremental recovery over primary production is variable but can reach as high as 25% of oil originally in place (OOIP) in places. This paper presents the history of the field and then focuses on the polymer-flooding aspects. It describes the preparation and results of the two polymer-flood pilots, as well as the extension of the flood to the rest of the field (currently in progress). Polymer flooding has generally been applied in light- or medium- gravity oil, and even currently, standard industry-screening criteria limit its use to viscosities up to 150 cp only. Pelican Lake is the first successful application of polymer flooding in much higher-viscosity oil (more than 1,200 cp), and as such, it opens a new avenue for the development of heavy-oil resources that are not accessible by thermal methods.
The Pelican Lake heavy oil field located in northern Alberta (Canada) has had a remarkable history since its discovery in the early 1970s. Initial production using vertical wells was poor because of the thin (less than 5m) reservoir formation and high oil viscosity (600 to over 40,000cp). The field began to reach its full potential with the introduction of horizontal drilling and was one of the first fields worldwide to be developed with horizontal wells. Still, with primary recovery less than 10% and several billion barrels of oil in place, the prize for EOR is large.
Initially, polymer flooding had not been considered as a viable EOR technology for Pelican Lake due to the high viscosity of the oil, until the idea came of combining it with horizontal wells. A first - unsuccessful - pilot was implemented in 1997 but the lessons drawn from that failure were learnt and a second pilot met with success in 2006. The response to polymer injection in this pilot was excellent, oil rate climbing from 43bopd to over 700bopd and remaining high for over 6 years now; the water-cut has generally remained below 60%.
This paper presents the history of the field then focuses on the polymer flooding aspects. It describes the preparation and results of the two polymer flood pilots as well as the extension of the flood to the rest of the field (currently in progress).
Polymer flooding has generally been applied in light or medium gravity oil and even today, standard industry screening criteria limit its use to viscosities up to 150cp only. Pelican Lake is the first successful application of polymer flooding in much higher viscosity oil (1,000-2,500cp) and as such, it opens a new avenue for the development of heavy oil resources that are not accessible to thermal methods.
Dupuis, Guillaume (Poweltec) | Al-Maamari, Rashid Salim (Sultan Qaboos University) | Al-Hashmi, Abdul Aziz (Sultan Qaboos University) | Al-Sharji, Hamed Hamoud (Petroleum Development Oman) | Zaitoun, Alain (Poweltec)
In a previous work (Zaitoun, et al., 2012), a study of the shear stability of different EOR polymers was reported. Shear stability was found to directly correlate to chain flexibility. Thus, for a flexible coil such as polyacrylamide, the presence of large monomer groups (e.g. ATBS, NVP) leads to an increase of its rigidity, hence enhancing its shear stability. However, these polymers remain highly shear sensitive in comparison to the rodlike Xanthan gum.
In this paper shear and thermal stability studies of different microgels are reported. Microgels are micrometric hydrophilic gel particles composed of partially cross-linked polyacrylamide-based chains. These microgels are already used for water shut-off treatments and conformance control. Because of their stability, they could be used in the future as sweep improvers EOR chemicals.
Comparative tests were performed with microgels and three different polyacrylamide-based EOR polymers in terms of shear and thermal stability. The impact of the internal cross-linking density, the size and the conditioning on microgels mechanical stability was investigated. For each microgel, solutions were prepared at different salinities and aged in ovens at 80, 105 and 140°C over one month in oxygen-free conditions to check their thermal stability.
Results showed that microgels maintain their integrity over a wide range of shear rate (up to 1.2x106 s-1) behaving like the rodlike Xanthan gum, whereas classical polyacrylamide-based polymers loose more than 50% of their initial viscosity at shear rate as low as 104 to 105 s-1. No difference in behavior is observed for the product prepared in powder or in emulsion form. Finally, at the highest temperature investigated (i.e. 140°C), thermal degradation is minimal for the microgels with low cross-linking densities and no thermal degradation has been observed for the microgels with the highest cross-linking densities.
The exceptional mechanical and thermal stability of the polyacrylamide-based microgels and their easiness to be tailored for the required application make these chemicals excellent candidates as future sweep improvers under harsh reservoir conditions in which other conventional polymers might fail.
Morvan, Mikel (Rhodia) | Degre, Guillaume (Rhodia) | Beaumont, Julien (Rhodia) | Colin, Annie (LOF (CNRS-Rhodia-Bx1)) | Dupuis, Guillaume (POWELTEC) | Zaitoun, Alain (POWELTEC) | Al-maamari, Rashid Salim (Sultan Qaboos University) | Al-Hashmi, Abdul-Aziz R. (Sultan Qaboos University) | Al-Sharji, Hamed Hamoud (Petroleum Development Oman)
Injections of polymer solutions have been used to improve oil recovery in heavy oil reservoirs (Zaitoun et al. 1998). Most of those polymer flood experiences refer to conditions where the polymer solution propagates through the porous media under low shear rate and exhibits mostly a Newtonian behaviour. On the other hand recent publications indicate injection of polymer solutions at concentration larger than conventional polymer flooding can result in higher recovery at field scale. Typically oil recovery of more than 20% OOIP compared to waterflooding has been reported for light oil (Wang et al; 2011). However injectivity issues have to be considered when injecting concentrated polymer solutions. This study examines whether non polymeric elastic fluids derived from surfactant solutions can represent an alternative approach to elastic polymer floods. The technology we have developed matches the rheological properties of polymer solutions in a broad range of reservoir conditions (temperature & salinity).
Bulk flow properties as well as rheology in a confined geometry have been used to compare flow properties of surfactant and high molecular weight polymer solutions. The elastic properties of both fluids have been characterized in terms of Weissenberg numbers. The data indicate the surfactant solution as opposed to the polymer one is highly elastic at low shear rates even in the presence of brine. Those results are confirmed by comparative experiments made using a Particle Image Velocimetry (PIV) technique. Injectivity of concentrated surfactant solutions has been tested in single-phase conditions and indicated a good in depth propagation of the fluid. A series of core-flood experiments has been performed using heavy oil reservoir cores. The surfactant slug has been combined with a conventional low-concentration polymer flooding to benefit from surfactant elasticity and improve oil recovery.