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Many gas wells in Adriatic Sea are suffering from both water and sand production. An original sand control polymer technology has been successfully implemented and has proven to be an efficient way to stop sand production and thus maintain gas well under steady production. In many wells, a reduction of water production was observed as side effect. Nevertheless, the main objective remained sand control and not water control.
The present paper describes a polymer treatment performed in an offshore well equipped with sand control gravel-pack downhole completion. This well was suffering of high level of water production inducing a severe decline in gas production. The preparation of the treatment consisted of lab coreflood tests aiming at checking the behavior of the selected polymer (P-321) in actual reservoir conditions. The product was shown to have good injectivity and to strongly adsorb on the reservoir rock. Moreover, it has good RPM properties, inducing a strong reduction in water relative permeability while preserving gas relative permeability.
The treatment proceeded in the bullhead mode, i.e. through the gravel pack. The polymer was followed by a Nitrogen postflush to squeeze the product deep in the formation and help restarting the well. Immediately after treatment, gas rate increased while water rate levelled off. Both gas rate and GWR (Gas Water Ratio) stopped declining and remained at same level for two years. After two years, the estimated additional gas production was 13,330 KSCM and the well keeps flowing steadily instead to be probably shut in if it had followed its initial decline trend.
Rodriguez, Laurent (SNF) | Antignard, Sebastien (SNF) | Giovannetti, Bruno (SNF) | Dupuis, Guillaume (SNF) | Gaillard, Nicolas (SNF) | Jouenne, Stephane (Total) | Bourdarot, Gilles (Total) | Morel, Danielle (Total) | Zaitoun, Alain (Poweltec) | Grassl, Bruno (Pau University IPREM)
This document is an expanded abstract.
Most of Middle East fields presents harsh reservoir conditions (high temperature, high salinity, low permeability carbonates) for polymers used as mobility control agents in EOR. Traditional synthetic polymers such as partially hydrolyzed polyacrylamide (HPAM) are not thermally stable. At temperatures higher than 60°C, acrylamide moieties hydrolyze rapidly in sodium acrylate which ultimately leads to precipitation and a total loss of viscosifying power. Thermal stability can be improved by incorporating more expensive monomers such as ATBS or NVP.
In a previous paper (Tulsa, 2014), we reported the development of terpolymers where the incorporation of NVP brought robustness up to 120°C. However, the use of NVP increased the cost of the polymer and limited its molecular weight. NVP also caused compositional drifts impairing injectivity in low permeability carbonate rocks. The price of the final product was 3 times higher than conventional HPAM polymers and 2 to 2.5 higher than SPAM polymers. In a more recent paper (ADIPEC, 2017), we reported the synthesis of NVP-free polymers having different contents of ATBS. These polymers presented had a lower cost than the NVP polymers and allowed a dosage reduction of 50% to get the same viscosity. They outperformed the NVP polymers in terms of injectivity and thermal stability pushing further the envelope of stability of EOR polymers up to 130°C and 140°C in brines having a TDS of 230 g/L and 100 g/L respectively.
In this study, we present new data of viscosity and thermal stability of the NVP-free polymers optimized in terms of process and molecular weight. In particular, the thermal stability study was completed with NMR spectroscopy and Size Exclusion Chromatography (SEC) analysis to bring information on the evolution of the chemistry and of the molecular weight distribution of the polymers under aging. Results showed that the optimization of these polymers allowed an additional dosage reduction of 30% compared to NVP polymers. NMR and SEC analysis revealed that the reduction of the viscosity during aging was due to an evolution of the chemistry by the formation of sodium acrylate but also to chain scission. ATBS appeared to slow-down hydrolysis and limit viscosity loss. No modification of the chemistry was observed for the polymer having the highest level of ATBS. Its viscosity loss was directly correlated to a decrease of its molecular weight.
The optimization of the NVP-free polymers allowed reducing their dosage by one third making them very attractive from an economic perspective. NMR and SEC have proven to be an efficient tool to better understand the evolution of the viscosity of the polymer solutions submitted to aging.
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.
This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohi bited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract 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.