Field Demonstration of the Impact of Fractures on Hydrolyzed Polyacrylamide Injectivity, Propagation, and Degradation

Summary During a polymer flood, the field operator must be convinced that the large chemical investment is not compromised during polymer injection. Furthermore, injectivity associated with the viscous polymer solutions must not be reduced to where fluid throughput in the reservoir and oil production rates become uneconomic. Fractures with limited length and proper orientation have been theoretically argued to dramatically increase polymer injectivity and eliminate polymer mechanical degradation. This paper confirms these predictions through a combination of calculations, laboratory measurements, and field observations (including step-rate tests, pressure transient analysis, and analysis of fluid samples flowed back from injection wells and produced from offset production wells) associated with the Kalamkas oil field in Western Kazakhstan. A novel method was developed to collect samples of fluids that were back-produced from injection wells using the natural energy of a reservoir at the wellhead. This method included a special procedure and surface-equipment scheme to protect samples from oxidative degradation. Rheological measurements of back-produced polymer solutions revealed no polymer mechanical degradation for conditions at the Kalamkas oil field. An injection well pressure falloff test and a step-rate test confirmed that polymer injection occurred above the formation parting pressure. The open fracture area was high enough to ensure low flow velocity for the polymer solution (and consequently, the mechanical stability of the polymer). Compared to other laboratory and field procedures, this new method is quick, simple, cheap, and reliable. Tests also confirmed that contact with the formation rapidly depleted dissolved oxygen from the fluids—thereby promoting polymer chemical stability.

ANALYSIS OF THE TEMPERATURE FIELD IN A MOLD CAVITY FOR POLYMER INJECTION PROCESS

A common situation in the design of injection molds is to achieve an efficient performance in terms of heat transfer, this will allow a higher production rate with better finished parts [1]. One of the most important factors in the design is the cooling time: about 80% of the processing time is determined by it [2]. Seeking to contribute with the increase of productivity, this work presents results of simulations through the finite volume method (MVF) of the injection molding process; those results are compared with an analysis of design of experiments (DOE) with different injection conditions, revealing the study variables that are fundamental to improve the process. Thus, a statistical analysis and a computer simulation analysis are presented to identify the variables inherent to the process and recommend their values.

The Effect of Surfactant Polymer Concentration on the Distribution of Oil Drainage Area in Heterogeneous Reservoir

The use of chemical injection has been widely used in the oil field on a large scale. One of the enhanced oil recovery (EOR) methods to increase production from old oil fields is through polymer surfactant injection, which functions to reduce interfacial tension and water-oil mobility ratio. This study focuses on developing a simulation model for chemical injection of polymer surfactant reservoirs by hypothetically making heterogeneous reservoir models in each layer with dimensions of 10x10x4. It consists of one a vertical well which is producer well located at the top of the left corner and one an injection well which is located at the bottom of right corner. This study shows a comparison between surfactant injection, polymer injection and SP injection using the same surfactant and polymer concentration with a concentration of 1000 ppm with 0.3 PV. Oil recovery in polymer injection turned out to be quite high compared to other chemical injections. In polymer injection, the oil recovery was 4.17%. Meanwhile, surfactant injection and SP injection increased by 0.59% and 0.61, respectively.

Effect of the Glass Fiber Content of a Polybutylene Terephthalate Reinforced Composite Structure on Physical and Mechanical Characteristics

This work presents the influences of glass fiber content on the mechanical and physical characteristics of polybutylene terephthalate (PBT) reinforced with glass fibers (GF). For the mechanical characterization of the composites depending on the GF reinforcement rate, tensile tests are carried out. The results show that increasing the GF content in the polymer matrix leads to an increase in the stiffness of the composite but also to an increase in its brittleness. Scanning Electron Microscope analysis is performed, highlighting the multi-scale dependency on types of damage and macroscopic behavior of the composites. Furthermore, flammability tests were performed. They permit certifying the flame retardancy capacity of the electrical composite part. Additionally, fluidity tests are carried out to identify the flow behavior of the melted composite during the polymer injection process. Finally, the cracking resistance is assessed by riveting tests performed on the considered electrical parts produced from composites with different GF reinforcement. The riveting test stems directly from the manufacturing process. Therefore, its results accurately reflect the fragility of the material used.

Polymer Injection to Unlock Bypassed Oil in a Giant Carbonate Reservoir: Bridging the Gap Between Laboratory and Large Scale Polymer Project

Polymer flooding has long been proposed to improve sweep efficiency in heterogeneous reservoirs where polymer enhances cross flow between layers and forces water into the low permeability layers, leading to more homogeneous saturation profile. Although this approach could unlock large volumes of by-passed oil in layered carbonate reservoirs, compatibility of polymer solutions with high salinity - high temperature carbonate reservoirs has been hindering polymer injection projects in such harsh conditions. The aim of this paper is to present the laboratory work, polymer injection field test results and pilot design aimed to unlock target tertiary oil recovery in a highly heterogeneous mixed to oil-wet giant carbonate reservoir. This paper focuses on a highly layered limestone reservoir with various levels of cyclicity in properties. This reservoir may be divided in two main bodies, i.e., an Upper zone and a Lower zone with permeability contrast of up to two orders of magnitude. The main part of the reservoir is currently under peripheral and mid-flank water injection. Field observations show that injected water tends to channel quickly through the Upper zone along the high permeability layers and bypass the oil in the Lower zone. Past studies have indicated that this water override phenomenon is caused by a combination of high permeability contrast and capillary forces which counteract gravity forces. In this setting, adequate polymer injection strategy to enhance cross-flow between these zones is investigated, building on laboratory and polymer injection test field results. A key prerequisite for defining such EOR development scenario is to have representative static and dynamic models that captures the geological heterogeneity of this kind of reservoirs. This is achieved by an improved and integrated reservoir characterization, modelling and water injection history matching procedure. The history matched model was used to investigate different polymer injection schemes and resulted in an optimum pilot design. The injection scheme is defined based on dynamic simulations to maximize value, building on results from single-well polymer injection test, laboratory work and on previous published work, which have demonstrated the potential of polymer flooding for this reservoir. Our study evidences the positive impact of polymer propagation at field scale, improving the water-front stability, which is a function of pressure gradient near producer wells. Sensitivities to the position and number of polymer injectors have been performed to identify the best injection configuration, depending on the existing water injection scheme and the operating constraints. The pilot design proposed builds on laboratory work and field monitoring data gathered during single-well polymer injection field test. Together, these elements represent building blocks to enable tertiary polymer recovery in giant heterogeneous carbonate reservoirs with high temperature - high salinity conditions.

Polymer Outage Strategy for On-Going Polymer Injection Operation in the Sultanate of Oman

Polymer outage (or polymer injection unavailability) is undesirable but also inevitable. When it happens, the question is how to respond to it to minimize its adverse impact on the production. This paper presents the rationale for generating a polymer outage strategy to operate a polymer flood field in the southern area of the Sultanate of Oman. The work presented here is based on field performance and analytical analysis. The diagnostic plots were created from 10 years of polymer flood field response and were used for this operating decision. The pros and cons of two scenarios were discussed. The selected operational strategy is to minimize the short falls of polymer outage. The strategy was implemented in the field. Simultaneous injection and production pause (SIPP) is recommended for the full field polymer outage. It minimizes the impact on polymer incremental oil and hence less deferment. Calibrated with the actual results, analytical method is used to determine when to shut down and whether a short of buffer period of water can be tolerated before SIPP is carried out. The polymer literature focus on polymer mechanisms, modeling, project initiation and implementation but no paper discusses the operational strategy on how to respond to field polymer outages. This paper shares our operational learnings and the field results of various polymer operation modes on polymer incremental oil. The learning from this field may be of interest to other operators who are planning or currently implementing polymer flood in their fields.

Pelican Lake: Learning From the Largest Polymer Flood Expansion in a Heavy Oil Field

Polymer has been injected continuously since 2005-06 in the Pelican Lake field in Canada, starting with a pilot rapidly followed by an expansion. At some point, 900 horizontal wells were injecting 300,000 bbl/d of polymer solution and oil production related to polymer injection reached 65,000 bopd. As a result, the Pelican Lake polymer flood is the largest polymer flood in heavy oil in the world and the largest polymer flood using horizontal wells. Although some papers have already been devoted to the initial polymer flood pilots, very little has been published on the expansion of the polymer flood and this is what this paper will focus on. The paper will describe the various phases of the polymer flood expansion and their respective performances as well as discuss the specific challenges in the field including strong variations in oil viscosity (from 800 to over 10,000 cp), how irregular legacy well patterns were dealt with, and how primary, secondary and tertiary polymer injection compare. It will also show the performances of polymer injection in combination with multi-lateral wells and touch upon the surface issues including the facilities. The availability of field and production data (which are public in Canada) combined with the variability in the field properties provide us with a wealth of data to better understand the performances of polymer flooding in heavy oil. This case study will benefit engineers and companies that are interested in polymer flood, in particular in heavy oil. The paper will be a significant addition to the literature where few large scale chemical EOR expansions are described.

Insights into Oil Recovery Mechanism by Nothing-Alternating-Polymer NAP Concept

This paper discusses the application of polymer injection in a heavy oil reservoir in the South of the Sultanate of Oman containing oil with a viscosity of 300-800cP underlain by a strong bottom-up aquifer. Due to unfavorable mobility ratio between aquifer water and oil and the development of the sharp cones significant amount of oil remains unswept. To overcome these issues, a polymer injection pilot started in 2013 with three horizontal injectors, located a few meters above the oil/water contact. Initially a polymer solution with a viscosity of 100 cP was continuously injected at high injection rates. However, it was challenging to sustain the injectivity mainly due to surface facilities, water, and polymer quality issues. This resulted in frequent shutdowns of the injectors. Interestingly, the water cut reversal and oil gain continued during the shut-in periods. This observation has led to the development of a new cyclic polymer injection strategy, in which the injection of polymer is alternated with shut-ins. The strategy is referred to as Nothing-Alternating-Polymer (NAP). This paper discusses the oil recovery mechanism from the NAP strategy. A 3D model was constructed to match the actual pilot results and capture the observed behavior. The injected polymer squeezes the cones and partly restores the barrier between the aquifer and the oil column, suppressing the aquifer flux and hence the negative affect of the cones. It was found that during polymer injection, the oil is recovered by conventional mobility and sweep enhancement mechanisms ahead of the polymer front. Additionally, during this stage the injected polymer creates a barrier between the aquifer and the oil column, suppressing the aquifer flux and hence the negative effect of the cones or water channels (blanketing mechanism). Moreover, injection of polymer pushes the oil to the depleted water cones, which is then is produced by the water coming from the aquifer during shut-in period (recharge mechanism). During the shut-in or NAP period, the aquifer water also pushes the existing polymer bank and hence leads to extra oil production. The NAP strategy reduces polymer loss into aquifer and improves the polymer utilization factor expressed in kg-polymer/bbl of oil, resulting in a favorable economic outcome.

Bulk Rheology and Injectivity Assessments of Potential Biopolymer and Synthetic Polymer for Applications in Carbonates Under Harsh Conditions

Polymer flooding is a well-established chemical EOR technology that is used to overcome challenges associated with conventional waterflooding including viscous fingering and early breakthrough. Nevertheless, polymers tend to perform poorly under harsh reservoir conditions of high temperature and high salinity (HTHS). The main objective of this study is to evaluate and compare the performance of two potential polymers, an ATBS-based polymer and a biopolymer (Scleroglucan), in carbonates under harsh reservoir conditions. This comparative study includes an analysis of polymer rheological experiments as well as polymer injectivity tests. The effects of water salinity and temperature on the performance of these two polymers was also investigated in this study. Rheological experiments were carried out on polymer samples at both ambient (25 °C) and high temperature conditions (90 °C). Polymer viscosity was measured as function of concentration, temperature, and salinity at different shear rates ranging from 1 to 1000 s−1. Injectivity characteristics of both polymers were also assessed through coreflooding experiments using high permeability carbonate outcrops at room (25 °C) and high (90 °C) temperature conditions. The injectivity tests included two stages of brine pre-flush and polymer injection, which allowed assessing the resistance factor (RF) of these polymers. These tests were conducted using high salinity formation water (167,114 ppm TDS) at both temperature conditions. The bulk rheological tests showed that both ATBS-based and Scleroglucan polymers exhibit a shear-thinning behavior. However, the shear-thinning effect is far more evident at higher concentrations in the case of Scleroglucan as opposed to that of the ATBS-based polymer. Viscosity measurements of the polymer samples at different salinities demonstrated the detrimental impact of salinity and divalent ions on the stability of ATBS-based whereas Scleroglucan was not much affected. Scleroglucan exhibited better filterability at the high temperature as opposed to the room temperature. From the injectivity tests, the shear-thinning behavior of the biopolymer in the porous media was confirmed as RF decreased with increasing the flow rate applied at both temperature conditions. Meanwhile, the ATBS-based polymer exhibited a shear-thickening behavior at 25 °C, but a shear-thinning one at 90 °C. Compared to the biopolymer, the ATBS-based polymer showed better injectivity at both the room and the high temperatures as the differential pressure stabilized within the first few pore volumes injected. This study highlights the importance of polymer screening for EOR applications in carbonate reservoirs under HTHS conditions.