An evaluation of the enhanced oil recovery potential of the xanthan gum and aquagel in a heavy oil reservoir in Trinidad

Abstract The economy of Trinidad and Tobago which mainly relies on its energy sector is facing significant challenges due to declining crude oil production in a low commodity price environment. The need for enhanced oil recovery (EOR) methods to meet the current and future energy demands is urgent. Studies on the use of polymer flooding in Trinidad and Tobago are limited, especially in terms of necessary data concerning the characterization of the adsorption of polymer flooding chemicals such as xanthan gum and aquagel polymers on different soil types in Trinidad and the viscosity characteristics of the polymer flooding solutions which affect the key attributes of displacement and sweep efficiency that are needed to predict recovery efficiency and the potential use of these flooding agents in a particular well. Adsorption and viscosity experiments were conducted using xanthan gum and aquagel on three different soil types, namely sand, Valencia clay (high iron) and Longdenville clay (low iron). Xanthan gum exhibited the lowest adsorption capacity for Valencia clay but absorbed most on sand at concentrations above 1000 ppm and Longdenville clay below 1000 ppm. At concentrations below 250 ppm, all three soil-type absorbent materials exhibited similar adsorption capacities. Aquagel was more significantly absorbed on the three soil types compared to xanthan gum. The lowest adsorption capacity was observed for Valencia clay at concentration levels above 500 ppm; however, the clay had the highest adsorption capacity below this level. Sand had the highest adsorption capacity for aquagel at concentrations above 500 ppm while Longdenville clay was the lowest absorbent above 500 ppm. Generally, all three soil types had a similar adsorption capacity for xanthan gum at a concentration level of 250 ppm and for aquagel at a concentration level of 500 ppm. The results offered conclusive evidence demonstrating the importance that the pore structure characteristics of soil that may be present in oil wells on its adsorption characteristics and efficiency. Xanthan gum polymer concentration of 2000 ppm, 1000 ppm and 250 ppm showed viscosities of 125 cp, 63 cp and 42 cp, respectively. Aquagel polymer concentrations of 2000 ppm, 1000 ppm and 250 ppm showed viscosities of 63 cp, 42 cp and 21 cp, respectively. Aquagel polymer solutions were found to generally have lower viscosities than the xanthan gum polymer solutions at the same concentration. Adsorption and viscosity data for the xanthan gum and aquagel polymers were incorporated within CMG numerical simulation models to determine the technical feasibility of implementing a polymer flood in the selected EOR 44 located in the Oropouche field in the southwest peninsula of the island of Trinidad. Overall, aquagel polymer flood resulted in a higher oil recovery of 0.06 STB compared to the xanthan gum polymer flood, so the better EOR method would be aquagel polymer flood. Additionally, both cases of polymer flooding resulted in higher levels of oil recovery compared to CO2 injection and waterflooding and therefore polymer flooding will have greater impact on the EOR 44 well oil recovery.

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Evaluation of an alkali-polymer flooding technique for enhanced oil recovery in Trinidad and Tobago

Journal of Petroleum Exploration and Production Technology ◽

10.1007/s13202-020-00981-7 ◽

2020 ◽

Vol 10 (8) ◽

pp. 3947-3959

Author(s):

Kyle Medica ◽

Rean Maharaj ◽

David Alexander ◽

Mohammad Soroush

Keyword(s):

Trinidad And Tobago ◽

Enhanced Oil Recovery ◽

Oil Recovery ◽

Energy Demand ◽

Xanthan Gum ◽

Net Present Value ◽

Flow Characteristics ◽

Absorption Capacity ◽

Polymer Flooding ◽

Screening Criteria

Abstract Trinidad and Tobago (TT) is seeking to develop more economical methods of enhanced oil recovery to arrest the decline in crude oil production and to meet the current and future energy demand. The utilization of alkaline-polymer flooding to enhance oil recovery in TT requires key studies to be conducted to obtain critical information of the flooding system (soil type, additive type, pH, adsorption characteristics and rheological (flow) characteristics). Understanding the role of, interplay and optimizing of these variables will provide key input data for the required simulations to produce near realistic projections of the required EOR efficiencies. The parameters of various wells in TT were compared to the screening criteria for alkali-polymer flooding, and the EOR 4 well was found to be suitable and thus selected for evaluation. Laboratory adsorption studies showed that the 1000 ppm xanthan gum flooding solution containing 0.25% NaOH exhibited the lowest absorption capacity for the gravel packed sand and exhibited the lowest viscosity at all the tested shear rates. The lowest adsorption was 2.27 × 10−7 lbmole/ft3 which occurred with the 1000 ppm xanthan gum polymer containing 0.25% NaOH, and the evidence showed that the polymer was adsorbed on the other side of the faults, indicating that it has moved further and closer to the producing well. Implementation of an alkali polymer flooding resulted in an incremental increase in the recovery factors (~ 3%) compared to polymer flooding; however, a change in the oil recovery as a function of the alkaline concentration was not observed. The simulated economic analysis clearly shows that all the analysed EOR scenarios resulted in economically feasible outcomes of net present value (NPV), Internal Rate of Return (IRR) and payback period for oil price variations between $35 and $60 USD per barrel of oil. A comparison of the individual strategies shows that the alkali-polymer flood system utilizing 0.25% sodium hydroxide with 1000 ppm xanthan gum is the best option in terms of cumulative production, recovery factor, NPV, IRR and time to payback.

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Laboratory Investigations of Factors Influencing Polymer Flood Performance

Society of Petroleum Engineers Journal ◽

10.2118/4669-pa ◽

1975 ◽

Vol 15 (04) ◽

pp. 338-346 ◽

Cited By ~ 21

Author(s):

M.T. Szabo

Keyword(s):

Oil Recovery ◽

Polymer Solutions ◽

Polymer Concentration ◽

Polymer Flooding ◽

Mobility Control ◽

Sweep Efficiency ◽

Experimental Conditions ◽

Polymer Injection ◽

Polymer Flood

Abstract Numerous polymer floods were performed in unconsolidated sand packs using a C14-tagged, cross-linked, partially hydrolyzed ployacrylamide, and the data are compared with brine-flood performance in the same sands. performance in the same sands. The amount of "polymer oil" was linearly proportional to polymer concentration up to a proportional to polymer concentration up to a limiting value. The upper limit of polymer concentration yielding additional polymer oil was considerably higher for a high-permeability sand than for a low-permeability sand. It is shown that a minimum polymer concentration exists, below which no appreciable polymer oil can be produced in high-permeability sands. The effect of polymer slug size on oil recovery is shown for various polymer concentrations, and the results from these tests are used to determine the optimum slug size and polymer concentration for different sands. The effect of salinity was studied by using brine and tap water during polymer floods under similar conditions. Decreased salinity resulted in improved oil recovery at low, polymer concentrations, but it had little effect at higher polymer concentrations. Polymer injection that was started at an advanced stage of brine flood also improved the oil recovery in single-layered sand packs. Experimental data are presented showing the effect of polymer concentration and salinity on polymer-flood performance in stratified reservoir polymer-flood performance in stratified reservoir models. Polymer concentrations in the produced water were measured by analyzing the radioactivity of effluent samples, and the amounts of retained polymer in the stratified models are given for each polymer in the stratified models are given for each experiment. Introduction In the early 1960's, a new technique using dilute polymer solutions to increase oil recovery was polymer solutions to increase oil recovery was introduced in secondary oil-recovery operations. Since then, this new technique has attained wide-spread commercial application. The success and the complexity of this new technology has induced many authors to investigate many aspects of this flooding technique. Laboratory and field studies, along with numerical simulation of polymer flooding, clearly demonstrated that polymer additives increase oil recovery. polymer additives increase oil recovery. Some of the laboratory results have shown that applying polymers in waterflooding reduces the residual oil saturation through an improvement in microscopic sweep efficiency. Other laboratory studies have shown that applying polymer solutions improves the sweep efficiency in polymer solutions improves the sweep efficiency in heterogeneous systems. Numerical simulation of polymer flooding, and a summary of 56 field applications, clearly showed that polymer injection initiated at an early stage of waterflooding is more efficient than when initiated at an advanced stage. Although much useful information has been presented, the experimental conditions were so presented, the experimental conditions were so variable that difficulties arose in correlating the numerical data. So, despite this good data, a systematic laboratory study of the factors influencing the performance of polymer flooding was still lacking in the literature. The purpose of this study was to investigate the effect of polymer concentration, polymer slug size, salinity in the polymer bank, initial water saturation, and permeability on the performance of polymer floods. The role of oil viscosity did not constitute a subject of this investigation. However, some of the data indicated that the applied polymer resulted in added recovery when displacing more viscous oil. The linear polymer-flood tests were coupled with tests in stratified systems, consisting of the same sand materials used in linear flood tests. Thus, it was possible to differentiate between the role of polymer in mobility control behind the flood front in each layer and its role in mobility control in the entire stratified system through improvement in vertical sweep efficiency. A radioactive, C14-tagged hydrolyzed polyacrylamide was used in all oil-recovery tests. polyacrylamide was used in all oil-recovery tests. SPEJ P. 338

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Can 25-cp Polymer Solution Efficiently Displace 1,600-cp Oil During Polymer Flooding?

SPE Journal ◽

10.2118/190321-pa ◽

2018 ◽

Vol 23 (06) ◽

pp. 2260-2278 ◽

Cited By ~ 8

Author(s):

R. S. Seright ◽

Dongmei Wang ◽

Nolan Lerner ◽

Anh Nguyen ◽

Jason Sabid ◽

...

Keyword(s):

Crude Oil ◽

Polymer Solution ◽

Relative Permeability ◽

Oil Recovery ◽

Polymer Solutions ◽

Water Saturation ◽

Field Application ◽

Polymer Flooding ◽

Solution Viscosity ◽

Polymer Flood

Summary This paper examines oil displacement as a function of polymer-solution viscosity during laboratory studies in support of a polymer flood in Canada's Cactus Lake Reservoir. When displacing 1,610-cp crude oil from field cores (at 27°C and 1 ft/D), oil-recovery efficiency increased with polymer-solution viscosity up to 25 cp (7.3 seconds−1). No significant benefit was noted from injecting polymer solutions more viscous than 25 cp. Much of this paper explores why this result occurred. Floods in field cores examined relative permeability for different saturation histories, including native state, cleaned/water-saturated first, and cleaned/oil-saturated first. In addition to the field cores and crude oil, studies were performed using hydrophobic (oil-wet) polyethylene cores and refined oils with viscosities ranging from 2.9 to 1,000 cp. In field cores, relative permeability to water (krw) remained low, less than 0.03 for most corefloods. After extended polymer flooding to water saturations up to 0.865, krw values were less than 0.04 for six of seven corefloods. Relative permeability to oil remained reasonably high (greater than 0.05) for most of the flooding process. These observations help explain why 25-cp polymer solutions were effective in recovering 1,610-cp oil. The low relative permeability to water allowed a 25-cp polymer solution to provide a nearly favorable mobility ratio. At a given water saturation, krw values for 1,000-cp crude oil were approximately 10 times lower than for 1,000-cp refined oil. In contrast to results found for the Daqing polymer flood (Wang et al. 2000, 2011), no evidence was found in our application that high-molecular-weight (MW) hydrolyzed polyacrylamide (HPAM) solutions mobilized trapped residual oil. The results are discussed in light of ideas expressed in recent publications. The relevance of the results to field applications is also examined. Although 25-cp polymer solutions were effective in displacing oil during our corefloods, the choice of polymer viscosity for a field application must consider reservoir heterogeneity and the risk of channeling in a reservoir.

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Dynamic contact angles in oil–aqueous polymer solutions

Physical Chemistry Chemical Physics ◽

10.1039/c6cp06132j ◽

2017 ◽

Vol 19 (4) ◽

pp. 3337-3348

Author(s):

Amer Al-Shareef ◽

P. Neogi ◽

Baojun Bai

Keyword(s):

Enhanced Oil Recovery ◽

Oil Recovery ◽

Polymer Solutions ◽

Dynamic Contact ◽

Contact Angles ◽

Polymer Flooding ◽

Important Process ◽

Aqueous Polymer

Polymer flooding is an important process in enhanced oil recovery.

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Evaluation of a low salinity water flooding with polymer gel treatment in Trinidad and Tobago

Journal of Petroleum Exploration and Production Technology ◽

10.1007/s13202-020-00991-5 ◽

2020 ◽

Vol 10 (8) ◽

pp. 3971-3981

Author(s):

Sanyah Ramkissoon ◽

David Alexander ◽

Rean Maharaj ◽

Mohammad Soroush

Keyword(s):

Trinidad And Tobago ◽

Oil Recovery ◽

Xanthan Gum ◽

Oil Production ◽

Polymer Flooding ◽

Water Flooding ◽

Caribbean Region ◽

Low Salinity ◽

Low Salinity Water ◽

Salinity Water

Abstract Trinidad and Tobago (TT) has a rich history of crude oil production and is still one of the largest oil- and gas-producing countries in the Caribbean region. The energy sector contributes approximately 35% of GDP to its economy; however, economic headwinds due to steadily decreasing oil production, low commodity prices and increased competition worldwide have highlighted the need for more economical methods of enhanced oil recovery (EOR) techniques. Although the use of low salinity polymer flooding for EOR has had success in other countries, critical information relating associated flooding system parameters such as soil type, additive type, adsorption characteristics, rheological (flow) characteristics, pH and salinity is not available and is critical if this type of EOR is to be implemented in TT. The nature and inter-relationship of these parameters are unique to a particular reservoir, and studies in this regard will provide key input data for simulations to produce near realistic projections of this EOR strategy. These projections can be used to evaluate the usefulness of a low salinity polymer flooding in TT and guide for the proper implementation of the strategy. The EOR 33 wells located in the lower Forest sands in Southern Trinidad was selected for study as they satisfied the screening criteria. Laboratory studies of the adsorption of xanthan gum concentrations of 0 to 4000 ppm in combination with NaCl solutions (0–40,000 ppm) onto gravel packed sand found that the mixture of 1000 ppm polymer containing 1000 ppm NaCl exhibited the lowest adsorption capacity. The Langmuir coefficients were derived for each salinity, and together with results from the viscosity studies were inputted within the simulation models. Simulations of a sector of the EOR 33 projected that the highest oil recovery occurred using NaCl < 2000 ppm was 11% greater than water flood. A combination of brine (NaCl < 2000 ppm) with gel technology (1000 ppm polymer) produced the highest oil recovery factor (54%), almost twice that of water flooding, the highest average reservoir pressure and lowest water cut value. The improved performance characteristics observed using low salinity water flood with xanthan gum gel for injection can be associated with improved displacement efficiency and improved the sweep efficiency suggesting the strategy to be a technically feasible option for the EOR well in Trinidad.

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Polymer flooding for enhanced oil recovery

Revista dos Trabalhos de Iniciação Científica da UNICAMP ◽

10.20396/revpibic262018954 ◽

2019 ◽

Author(s):

Marcelo Eduardo Novaes Freire Filho ◽

Rosangela Barros Zanoni Lopes Moreno

Keyword(s):

Mathematical Models ◽

Enhanced Oil Recovery ◽

Oil Recovery ◽

Polymer Solutions ◽

Rheological Behaviour ◽

Oil Industry ◽

Polymer Flooding ◽

Viscous Fluids ◽

Reservoir Rocks ◽

Recovery Methods

In this work, Enhanced Oil Recovery methods were studied, with a focus on polymer flooding. Several works were surveyed to verify which parameters most affect the rheological behaviour of polymer solutions. Characteristics of reservoir rocks, important definitions of the oil industry and mathematical models of the rheology of viscous fluids were investigated as well.

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Enhanced Oil Recovery by a Horizontal Well Located Inside a Polymer Flood Pilot

Revue de l Institut Français du Pétrole ◽

10.2516/ogst:1990002 ◽

1990 ◽

Vol 45 (1) ◽

pp. 39-50

Author(s):

F. Foxonet ◽

L. Bruckert

Keyword(s):

Enhanced Oil Recovery ◽

Oil Recovery ◽

Horizontal Well ◽

Polymer Flood

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Experimental investigation of the displacement flow mechanism and oil recovery in primary polymer flood operations

SN Applied Sciences ◽

10.1007/s42452-021-04360-7 ◽

2021 ◽

Vol 3 (5) ◽

Author(s):

Ruissein Mahon ◽

Gbenga Oluyemi ◽

Babs Oyeneyin ◽

Yakubu Balogun

Keyword(s):

Relative Permeability ◽

Oil Recovery ◽

Polymer Flooding ◽

Mobility Control ◽

List Type ◽

Motor Oil ◽

Flow Mechanism ◽

Fractional Flow ◽

Recovery Method ◽

Polymer Flood

Abstract Polymer flooding is a mature chemical enhanced oil recovery method employed in oilfields at pilot testing and field scales. Although results from these applications empirically demonstrate the higher displacement efficiency of polymer flooding over waterflooding operations, the fact remains that not all the oil will be recovered. Thus, continued research attention is needed to further understand the displacement flow mechanism of the immiscible process and the rock–fluid interaction propagated by the multiphase flow during polymer flooding operations. In this study, displacement sequence experiments were conducted to investigate the viscosifying effect of polymer solutions on oil recovery in sandpack systems. The history matching technique was employed to estimate relative permeability, fractional flow and saturation profile through the implementation of a Corey-type function. Experimental results showed that in the case of the motor oil being the displaced fluid, the XG 2500 ppm polymer achieved a 47.0% increase in oil recovery compared with the waterflood case, while the XG 1000 ppm polymer achieved a 38.6% increase in oil recovery compared with the waterflood case. Testing with the motor oil being the displaced fluid, the viscosity ratio was 136 for the waterflood case, 18 for the polymer flood case with XG 1000 ppm polymer and 9 for the polymer flood case with XG 2500 ppm polymer. Findings also revealed that for the waterflood cases, the porous media exhibited oil-wet characteristics, while the polymer flood cases demonstrated water-wet characteristics. This paper provides theoretical support for the application of polymer to improve oil recovery by providing insights into the mechanism behind oil displacement. Graphic abstract Highlights The difference in shape of relative permeability curves are indicative of the effect of mobility control of each polymer concentration. The water-oil systems exhibited oil-wet characteristics, while the polymer-oil systems demonstrated water-wet characteristics. A large contrast in displacing and displaced fluid viscosities led to viscous fingering and early water breakthrough.

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