Single-well Chemical Tracer Research Articles

Novel single well chemical tracer test design: shut-in time determination for test feasibility

The well shut-in time (t soak) in a single-well chemical tracer test (SWCTT) after injection of the primary tracer depends on its reactivity under reservoir conditions. In this paper, a novel SWCTT design is proposed to determine the well shut-in time to minimize the risk of loss of test results based on different secondary tracer generation rates considering the oil saturation of the reservoir. The developed method in this paper was approximated to conduct SWCTT in oilfield A in predicting the minimum t soak after ethyl acetate injection for different S or. The paper shows that the field test tracer production curves are consistent with hydrodynamic modeling data at the same t soak. When t soak is reduced according to the model data, the concentration profile of the secondary tracer is in the low detection range, indicating that the test was properly organized when the well shut-in to minimum t soak. Thus, the novel test design showed how the time of all well operations can be optimized and the costs associated with equipment mobilization and service company operations can be reduced.

Low-Salinity Waterflooding for EOR in Field A of Western Offshore Basin: A Pilot Study Analysis with Laboratory and Simulation Studies—Early Observations

Carbonate reservoirs hold vast oil reserves, but their complex properties make traditional enhanced oil recovery (EOR) methods challenging. This study explores the application of low-salinity water flooding (LSWF) as a novel EOR method for India’s largest offshore carbonate oil field. Conventional EOR techniques were deemed unsuitable due to reservoir heterogeneity, pressure decline, high temperature, and the offshore location. Favorable factors for LSWF included successful seawater flooding history, medium-weight crude oil, and existing infrastructure. Following core flooding experiments demonstrating a 6–16% increase in oil recovery, a multi-pronged evaluation process was implemented. Single-well chemical tracer tests (SWCTT) and reservoir simulations confirmed the potential of LSWF. A specific target area was chosen based on reservoir characteristics, production data, and available facilities. Simulations predicted a 1.5% incremental oil recovery using diluted seawater (25% salinity) at 30% pore volume injection. After a positive techno-economic analysis, the first offshore LSWF project in India was completed within 3 years. Initial monitoring results are encouraging. This study highlights the successful journey of LSWF from concept to field deployment in a challenging carbonate reservoir, showcasing its potential for revitalizing such fields. Furthermore, this work provides valuable data relevant to Indian offshore environments, where factors like salinity, mineralogy, and crude oil composition pose unique challenges compared to other LSWF applications. These detailed data fill a critical gap in the existing literature.

Review of Offshore Chemical Flooding Field Applications and Key Lessons Learned

Summary This paper presents an overview of both current advancements and field applications of offshore chemical flooding technologies. Along with offshore oilfield development strategies that require the maximization of oil production in a short development cycle, chemical flooding can become a potential avenue to accelerate oil production in secondary oil recovery mode. This makes it different from onshore chemical flooding processes that mostly focus on enhanced oil recovery in mature or maturing reservoirs. The advancements in offshore chemical flooding field applications are reviewed and analyzed. By summarizing offshore application cases, the presented analysis also assesses the chemical formulations applied or studied and injection/production facilities required in offshore environments. The main technical challenges are also discussed for scaling up the applications on offshore platforms or floating production storage and offloading (FPSO) systems. The chemical flooding technologies reviewed include polymer flooding, surfactant-polymer (SP) flooding, and alkaline-surfactant-polymer (ASP) flooding. By assessing the technology readiness level of these technologies, this study presents their perspectives and practical relevance for offshore chemical flooding applications. It has been long realized that chemical flooding, especially polymer flooding, can improve oil recovery in offshore oil fields. The applications in Bohai Bay (China), Dalia (Angola), and Captain (North Sea) provide the know-how workflows for offshore polymer flooding from laboratory to full-field applications. It is feasible to implement offshore polymer injection either on a platform or in an FPSO system. It is recommended to implement polymer flooding at an early stage of reservoir development to maximize the investment in offshore facilities. By tuning the chemistry of polymer products, they can present very good compatibility with seawaters. Therefore, choosing a proper polymer is no longer a big issue for offshore polymer flooding. There are also some interesting findings reported on the development of novel surfactant chemistries for offshore applications. The outcome from a number of small-scale trials, including the single-well chemical tracer tests on surfactant, alkaline-surfactant (AS), and SP in offshore Malaysia, Abu Dhabi, Qatar, and South China Sea, provided valuable insights for the feasibility of chemical flooding in offshore environments. However, the technology readiness levels of surfactant-based chemical flooding processes are still low, partially due to their complex interactions with subsurface fluids and the lack of interest in producing residual oil from matured offshore reservoirs. Based on the lessons learned from offshore applications, it can be concluded that several major challenges still need to be overcome in terms of large well spacing, reservoir voidage, produced fluid treatment, and high operational expense to successfully scale up surfactant-based chemical flooding processes for offshore applications. Key Terms and Phrases offshore chemical flooding; polymer flooding; surfactant-based chemical flooding; offshore application cases; lessons learned

Evaluation of the Kinetic and Thermodynamic Behavior of Tracers for Their Applicability in SWCTT

Determining residual oil saturation by the single-well chemical tracer test (SWCTT) is of key importance for assessing the potential of enhanced oil recovery (EOR) and developing EOR pilot projects. However, the test trials conducted since the first injections of tracer compositions until now have not resulted in a detailed analysis of the selection of candidates for single-well tracers and their limits of applicability in various reservoir conditions. The purpose of this study was to consider the influence of the structure on the kinetic and thermodynamic components of tracers to assess their application’s operating intervals. It is shown that the rate of single-phase and two-phase hydrolysis of the primary partitioning tracer makes it possible to predict the shut-in time by calculating when the tracer is injected at the reservoir temperature. The influence of the tracer structure during the extraction process with an increase in the hydrocarbon chain of the ester in a different range of brine salinity and temperature has been studied. As a result, this work provides a method for evaluating the thermodynamic and kinetic behavior of primary tracers to establish minimum and maximum threshold K-values at various values of residual oil saturation, temperature, and brine salinity, taking into account the optimal time of the well shut-in to carry out at least 1/2 hydrolysis of esters.

New and simple methods of determination partition coefficient and degree hydrolysis of tracer for estimating residual oil saturation by SWCTT technologies

SWCTT (Single-Well Chemical Tracer Test) actively used to determine the reservoir oil saturation as cost effective and quick method. To use this technology, the partition coefficients K and hydrolysis degree H of the tracer which determined experimentally in laboratories are essential for calculation of residual oil and estimation shut-off period of the well. In this paper, FTIR-spectroscopy and pH-metry were proposed for determination of partition coefficient of chemical tracer (ethyl acetate) and hydrolysis degree. Results obtained by these methods showed good correspondence with the data obtained by standard gas chromatographic analysis that confirms its applicability. All of these methods were used for the study of SWCTT parameters for four oilfields with different formation temperatures in the range 27–70 °C and formation water salinities up to 215,015 ppm. It was shown that oil-water partition coefficient of partitioning tracer increases with the rise of salinity. The apparent activation parameters of the hydrolysis reaction were determined by data on the degree of hydrolysis (pH-metry) and the concentration changes of tracer (head space gas chromatography analysis).

A Single Well Chemical Tracer model that accounts for temperature gradients, pH changes and buffering

We present the first ever Single Well Chemical Tracer (SWCT) model that incorporates temperature gradients and pH-driven ethyl acetate hydrolysis rate changes when buffering by either calcite in the oil-bearing formation or by chemical species in the injected brine are accounted for. The model is applied to four generic cases with SWCT test, rock formation and brine composition data based on published values. An analytical model is used to calculate how the brine injection temperature decreases with time and an axially symmetric numerical model is used to simulate the cooling of the oil-bearing formation, chemical reactions and transport of species in the reservoir. The primary oil-water partitioning tracer ethyl acetate hydrolyses into the secondary water tracer ethanol and acetic acid that lowers the pH and changes the hydrolysis rate. The acid driven pH decrease may be significantly reduced by pH buffering mechanisms. We investigate four different buffer models. Model 1 may represent a sandstone with calcite cement. In Model 2, also with calcite cement, the brine has less calcium but more bicarbonate and initially lower pH than Model 1. Model 3 is a clean sandstone without calcite cement and the brine contains no calcium but much bicarbonate. Model 4 has no buffer capacity neither in the brine nor in the target formation. Although we discuss only four models, they are quite different and represent an important subset of the realistic SWCT test parameter space. A temperature gradient develops across the primary tracer bank in all four models and this causes the secondary tracer to be displaced away from the wellbore relative to the primary tracer. We find that most of the ethyl acetate hydrolysis takes place during shut-in. The residual oil saturation (Sor) is estimated from the synthetic tracer production curves using the simple chromatographic separation equation as well as with the mean residence time correction. The two methods underestimate the true Sor value (22%) by 3–5 and 3–11% (saturation points), respectively. These results demonstrate that the ‘handicap’ created by the temperature gradient together with the pH-driven hydrolysis rate changes should be taken into account in Sor estimates. We suggest that SWCT tests may be used to evaluate the effective wettability of the target formation at a modest extra cost. Using water tracers with very low quantification limits as primary tracers should reduce or even eliminate the problems caused by temperature gradients and pH-driven hydrolysis rate changes since they will travel well ahead of the temperature gradient and the small amount of acid generated will produce only an insignificant reduction in pH.

Temperature gradient and pH effects on Sor estimates from SWCT tests - The no buffer case

Residual oil saturation (Sor) is the fraction of immobile oil that remains after a water flood. This information is important for calculating recoverable reserves and evaluating EOR campaigns. Single Well Chemical Tracer (SWCT) tests yield a near-well average Sor based on a large rock volume. Correctly performed and analyzed, SWCT tests yield reliable Sor estimates. There are, however, two important effects that commonly are ignored. One is cooling of the reservoir during injection of the cold brine resulting in decreased hydrolysis rate of the primary tracer. The other is the hydrolysis rate's pH dependence. To study these phenomena, we have developed a numerical model of an ethyl acetate SWCT test and applied it to a generic case with test and formation data based on published values. An analytical model is used to calculate how the brine injection temperature varies with time. The ethyl acetate hydrolyses into ethanol and acetic acid that lowers the pH and changes the hydrolysis rate. Any buffer capacity in the injected fluid or formation is neglected. Our model is the first ever to combine realistic temperature calculations with pH dependent ethyl acetate hydrolysis rate during a SWCT test. Sor is estimated from synthetic tracer production curves using the direct chromatographic separation equation as well as the mean residence time. A large number of simulations were performed to investigate how the Sor estimates vary with different model assumptions and input data. In all cases, both methods underestimate the true Sor, typically by 2–4% - in some cases significantly more. We demonstrate that neglecting dispersion in the wellbore during injection and production is warranted with the rock and test data used in this study.

Surface-Charge Alteration at the Carbonate/Brine Interface During Single-Well Chemical-Tracer Tests: Surface-Complexation Model

Summary Water chemistry has been shown to affect oil recovery by affecting surface charge and rock dissolution. The single-well chemical-tracer (SWCT) test is a field method to measure residual oil saturation (Sor), in which hydrolysis reaction of an ester has been known as a key process that could displace the equilibrium state of a reservoir by changing formation-water (FW) composition. Because oil mobilization during the SWCT tests causes an error in the measurement of Sor, changes in water chemistry might be a concern for the accuracy of Sor measurements. In our previous work, the extent to which different reservoir parameters might change water composition and the effect of water-chemistry changes on the calcite dissolution and the oil liberation from the carbonate-rock surfaces were extensively evaluated. In this study, the effect of water-chemistry changes on surface-charge alteration at the carbonate/brine interface has been studied by constructing and applying a surface-complexation model (SCM) that couples bulk aqueous and surface chemistry. We present how the pH drop induced by the displacement of the equilibrium state and changes in water chemistry in the formation affect surface charge in a pure-calcite carbonate rock during the SWCT tests. The results show that a pH drop during the SWCT tests while calcium concentration is held constant in the FW by ignoring calcite dissolution yields a less-positive/more-negative surface charge so that wettability of carbonate rock might be altered to a less-oil-wetting state, when the oil is negatively charged. In reality, however, calcite dissolves by water-chemistry changes during the SWCT tests, which leads to an increasing calcium concentration in the FW. Consequently, an SWCT test in carbonates is accompanied by increasing calcium concentration while pH drops, which yields an increase in the surface charge of carbonate rocks. Therefore, the pH drop does not directly affect the surface charge of carbonate rock during an SWCT test, and calcium concentration increased from calcite dissolution could control the surface charge more significantly.

A Step Change for Single-Well Chemical-Tracer Tests: Field Pilot Testing of New Sets of Novel Tracers

SummaryThe single-well chemical-tracer test (SWCTT) is an in-situ test to measure oil saturation, and has been used extensively to assess the potential for enhanced oil recovery (EOR) or to qualify particular EOR chemicals and methods. An SWCTT requires that a primary tracer be injected and that a secondary tracer be generated from the primary tracer in situ. Typically, a few hundred liters of ester is injected as primary tracer, and the secondary tracer is formed through hydrolysis in the formations. The ester is an oil/water-partitioning tracer, whereas the in-situ-generated alcohol is a water tracer. During production, these tracers separate and the time lag of the ester vs. the alcohol is used to estimate oil saturation in the near-well region.In this paper, we report a field test of a class of new reacting tracers for SWCTTs. In the test, approximately 100 cm3 of each of the new tracers was injected and used to assess oil saturation. In the test, ethyl acetate (EtAc) was used as a benchmark to verify the new tracers. This paper reviews the design and implementation of the test, highlights operational issues, provides a summary of the analyzed tracer curves, and gives a summary of the interpretation methodology used to find oil saturations from the tracer curves. Briefly summarized, we find the Sor measured by each of the novel tracers to compare with that from a conventional SWCTT. To validate stability and detectability of the tracers, a mass-balance assessment for the new tracers is compared with that of the conventional tracers.A benefit of the new tracers is the small amount needed. Methodological advantages resulting from using small amounts include the possibility to inject a mix of several tracers. Using several tracers with different partitioning coefficients enables probing of different depths of the reservoir. In addition, the robustness of SWCTTs can be increased by using several tracers, with different reaction rates and temperature sensitivity. The field trial also demonstrated that the new tracers have operational advantages. One benefit is the possibility to inject the new tracers as a short pulse of 10 minutes. Other benefits are that the small amounts needed reduce operational hazards and ease logistical handling.

Significance of Geochemistry in Single-Well Chemical-Tracer Tests by Coupling a Multiphase-Flow Simulator to the Geochemical Package

Summary Single-well chemical tracer (SWCT) is the most commonly used field method to determine oil or water saturation in one-well enhanced-oil-recovery (EOR) pilots. Because hydrolysis of an ester, which is the main part of the method, leads to forming acid as well as alcohol, the equilibrium state of the reservoir is disturbed, and thus the pH changes. It is generally accepted that the hydrolysis-reaction rate is mainly dependent on the pH and temperature. Therefore, it is required to know the extent to which this dependency might affect the shape of the product-tracer profiles and the numerical interpretation of the field-test data for computing residual oil saturation (Sor). In this study, this notion has been investigated by coupling a multiphase-flow simulator to the geochemistry package PHREEQC (Parkhust and Appelo 2013). In this study, the PHREEQC geochemical simulator has been used to illustrate the extent to which different parameters might affect the pH variation during the test. The PHREEQC database has been modified to take the ester-hydrolysis reaction into account by adding the ester, alcohol, and acid-product species. The hydrolysis-reaction mechanisms of ester have also been programmed to account for the dependency of the hydrolysis reaction on the pH. Also, because ester partitions into the oil phase and travels behind the water phase (i.e., Darcy velocity), performing two-phase flow would be necessary to highlight the significance of the pH dependency of the hydrolysis-reaction rate on the tracer profiles. For doing that, a multiphase Buckley-Leverett (BL) flow simulation is coupled with IPhreeqc, which is an open-source module of the PHREEQC geochemical package. Then, a California Turbidite SWCT test has been re-evaluated to verify the approach. At the end, the geochemistry of a reservoir with an almost weak resistance (high temperature and weak buffer capacity) against pH variation in the SWCT test has been studied using the geochemical-based approach. The results show that the variation of the hydrolysis rate with pH could affect mainly the tail edge of the predicted tracer profiles, and it could marginally affect the apex of the profiles; however, it might affect the interpreted value of the Sor measurement as the resistance against pH variation becomes weaker. In these conditions, adapting the SWCT-test designs (i.e., shut-in time and injecting lower concentration of ester) could diminish the pH variation. The pH dependency of the hydrolysis-reaction rate is recommended for the numerical interpretation of the field SWCT-test data. The results of this study can be used to minimize the uncertainties of the SWCT tests and to improve the reliability of the Sor measurements.

Studying the Potential of Calcite Dissolution on Oil Liberation from Rock Surfaces during Single-Well-Chemical-Tracer Tests by Coupling a Multiphase Flow Simulator to the Geochemical Package

Calcite mineral dissolution has been considered to be an important mechanism for dampening the considerable pH-variation during Single-Well-Chemical-Tracer (SWCT) tests by improving the buffer capacity of the aqueous solution. Other parameters that also could have a great effect on the geochemistry of the reservoir during the SWCT tests are water buffer capacity, soluble hydrocarbon components, and temperature. Additionally, calcite mineral dissolution has been also presented over the last decade as an underlying mechanism for liberation of the adsorbed oil from the surface by modified salinity water injection (MSWI) in carbonate reservoirs. This contradiction of effects of calcite dissolution might pose a challenge for the accuracy of the SWCT tests in carbonates. This concern motivated us to highlight the potential of the calcite dissolution on the oil liberation from the carbonate rock surfaces during the SWCT tests by coupling a multiphase flow simulator to the geochemistry package PHREEQC. The results show that although the calcite dissolution is marginal during injection time, it might be substantial during shut-in time which is much longer. During shut-in time, the results show that the potential of calcite dissolution on the oil liberation from the rock surfaces could be more significant at higher reservoir temperatures although initial solid calcite concentration and buffer capacity also could have an effect. It is also clear that the pH of the system reaches the lowest level when the shut-in time reaches the transient time (i.e., injection and production times) and it is not changed significantly afterwards. At longer shut-in times, the additional ester hydrolysis and acid product is neutralized by the calcite dissolution and the buffer capacity of water. Therefore, the probability of the liberation of the adsorbed oil from the rock surface is higher at larger shut-in times so that test designs with shorter shut-in times and even as short as the transient time for the carbonate reservoirs is highly recommended. We hope that this study can be used to minimize the uncertainties of the SWCT tests and improve the reliability of the Sor measurements.

Effect of Reservoirs Conditions on Designing Single-Well Chemical Tracer Tests Under Extreme Brine Conditions

The single-well chemical tracer test (SWCTT) has emerged in the past decades as a method for measuring oil saturation prior to and/or after EOR operations, to measure the recovery performance in-situ. To use this technology, the partition coefficients of the selected tracers are essential for estimating the level of residual oil at the targeted single well. Commonly, injection of short chain alcohols and ethyl acetate, a reactive tracer, is carried out for the tracer slug, mainly based on site-specific reservoir conditions, to accurately determine the level of oil saturation in-situ. However, injection of ethyl formate has been less common due to its fast hydrolysis rate under elevated temperature, which increases the challenges in data interpretation. Therefore, a systematic study for using ethyl formate under mid-range temperature $$(<60\,^{\circ }\hbox {C})$$ , as commonly found in mature oil field in the USA, shows the potential to be applied for SWCTT. As part of the design effort for a series of EOR field tests to manage the project risk, we particularly assessed the relationships between the partition coefficients of reactive tracers and subsurface conditions such as salinity, temperatures, type of electrolytes, and the equivalent alkane carbon number (EACN) of the crude oil experiments was performed under various reservoir conditions as a function of actual site characteristics at the targeted high saline formations. In brief, our data clearly show that the (oil/water) partition coefficient of ethyl formate increases steadily with increasing NaCl concentrations, ranging from 10,000 (0.17 M) to 250,000 mg/L (4.28 M). A similar upward trend was observed for increasing temperature between 25 and $$52\,^{\circ }\hbox {C}$$ ; however, the partition coefficient decreases inversely with increasing the crude oil EACN over the range from 8 to 12, which are common for domestic oil samples. It was also showed that brine with high NaCl concentration yielded higher partition coefficients. In contrast, brine with high $$\hbox {CaCl}_{2}$$ and $$\hbox {BaCl}_{2}$$ concentration yielded lower values. And $$\hbox {MgCl}_{2}$$ performed somewhat unusual trend in our tests. These results further indicate that the partition coefficient of the reactive tracer, ethyl formate, is sensitive to change in salinity, temperatures, type of electrolytes and EACN, as observed for other chemical tracers. In addition, based on the hydrolysis rate of ethyl formate under various reservoir conditions, the appropriate window of shut-in time can be pre-determined before initiating the field test. We believe that the ability of better understanding the partition coefficients and predicting the shut-in time beforehand could drastically reduce the risks of SWCTT operations.

A comprehensive framework for the theoretical assessment of the single-well-chemical-tracer tests

Single-well-chemical-tracer (SWCT) is the most commonly used field method to determine oil or water saturation in one-spot pilot. This method is a complex process due to many effective parameters and non-ideality factors involved. Understanding the extent to which theses parameters might affect the SWCT test profiles could help us to manage and design the SWCT test more efficient at different reservoir conditions. This paper proposes a comprehensive framework of a new approach to highlight different aspects of the SWCT tests theoretically before implementing the field test. In order to accomplish the task, combining of numerical and analytical solutions have been used.The devised algorithm has been programmed in six different stages. In the first four stages, all test design parameters in different investigation regions and retardation factors are calculated. The test design parameters are sizing the test volume, test timing (i.e., injection, shut-in, and production), tracer concentration during the test, and the mean residence volume. In the fifth stage, all criteria are taken into consideration to find the most efficient test designs. Then, the achieved parameters are applied in the simulation stage (sixth stage) to investigate the effect of the ester bank and concentration, ester properties, shut-in time. The geochemical speciation code PHREEQC is also used to study the level of pH-variation during shut-in time. The effects of the calcite dissolution, temperature, and initial buffer capacity have been evaluated on the probability of pH-variation. The results show that the probability of pH-variation increases with temperature and lower amount of calcite concentration.To evaluate the workflow methodology, two different field test cases with different reservoir conditions are employed in order to reflect the influence of different stages of the algorithm. We hope that the workflow developed can be used to minimize the uncertainties and improve the quality of the SWCT tests.

An innovative technique for determining residual and current oil saturations using a combination of Log-Inject-Log and SWCT test methods: LIL-SWCT

Abstract It is generally recognized that the determination of current oil saturation (Soc) and residual oil saturation (Sor) plays a significant role in production forecasting and the selection and management of enhanced oil recovery (EOR) methods. Failure to accurately determine either saturation state will lead to incorrect recovery estimates and poor understanding of EOR efficacy. While there exist several methods of determining Soc and Sor, each method benefits and suffers from advantages and disadvantages specific to that technique. In order to compensate for the shortcomings of any one specific method, a combination of testing procedures may be utilized. In this paper, we propose a combination of Log-Inject-Log (LIL) and single-well chemical tracer (SWCT) test methods to improve the accuracy of Sor measurement while simultaneously offering a novel approach to the determination of Soc. The proposed method is not still implemented in any field and in this case, the concept is offered, not confirmation through a field example. The LIL method has the advantage of being able to generate a vertical fluid saturation profile throughout a logged interval, but suffers from its strong dependence on porosity assumptions. Subsequently, any deviation between assumed porosity and actual porosity will result in a deviation between measured Sor and true Sor. By comparison, the SWCT test method is independent of porosity, but cannot detect vertical variations in Sor.The complimentary nature of these two test methods, as well as their operational reliance on fundamentally different principles, make them ideal candidates for a hybrid testing program to measure Sor with a high degree of quality assurance. As well, combining the LIL and SWCT test methods in a single testing program offers a novel approach to measuring Soc. The details and mathematical derivation of the theory behind the measurement of Sor and Soc via this hybrid approach are presented in this paper.

UK Field Benefits From Reduced-Salinity Enhanced-Oil-Recovery Implementation

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 161750, ’Low-Salinity Enhanced Oil Recovery, Laboratory to Day-1 Field Implementation—LoSal EOR Into the Clair Ridge Project,’ by Enis Robbana, SPE, Todd Buikema, Chris Mair, SPE, Dale Williams, Dave Mercer, Kevin Webb, SPE, Aubrey Hewson, and Chris Reddick, SPE, BP, prepared for the 2012 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 11-14 November. The paper has not been peer reviewed. BP has shown, by use of its reduced-salinity (RS) water-injection technology, that incremental increases in oil recovery can be achieved across length scales associated with coreflood experiments (inches), field-based single-well chemical-tracer tests (feet), and field trials (interwell distances). This paper discusses the process undertaken by the Clair Ridge project in getting RS enhanced oil recovery (EOR) adopted as a Day-1 secondary waterflood. Introduction Clair Ridge Field Overview. Containing more than 6 billion bbl of oil in place, Clair is the largest oil accumulation in the UK continental shelf, and it lies 142 miles north of the Scottish mainland and 35 miles west of the Shetland Islands in 132–155 m of water. The Clair A platform is a lightweight-steel- jacket development that was designed to be economic across the range of expected reservoir outcomes. The main risk at startup was whether waterflood of the fractured reservoir would work. More than 5 years of production data indicate that the reservoir production mechanism in Clair Phase 1 is working. There is evidence of displacement of oil from the matrix by a combination of viscous sweep, gravity drainage, and imbibition of water from the fracture network into the matrix. Success at Clair Phase 1 has paved the way for a much larger Clair Phase 2 development. The next phase of development will target roughly twice the oil in place of Clair Phase 1 in an area that has generally shallower and thicker reservoir, known as Clair Ridge. During development, various EOR schemes were studied. Gasflooding of the reservoir would be hampered by adverse relative permeability factors. These can be improved by enriching the gas with heavier components such as propane and butane; however, there is not a large source of these materials in the basin. Modeling has shown that the open fractures are expected to provide a shortcut between gas-injection and production wells. Alternatives such as CO2 flooding and polymer flooding were also considered and rejected. Clair is a waterflood reservoir, and recovery depends on sweeping the large areas of matrix rock between the conductive fractures. What Is RS EOR? RS EOR can be defined as waterflooding of a sandstone oil reservoir using water with total-dissolved-solids (TDS) content of less than 2,000–8,000 ppm. The RS-flood TDS threshold shows some variation across different reservoir/fluid systems, with consistent enhanced recovery below the lower end of the range and varied effect within the range. Full-reservoir-condition RS EOR corefloods have been performed on many reservoir systems across the world. All tests have shown similar characteristics, with increased oil production at water breakthrough and a decrease in remaining-oil saturation at the end of the waterflood tests. RS EOR recovers additional oil after both secondary (RS water injection from Day 1) and tertiary (RS injection following higher-salinity- water injection) waterflood applications. Figs. 1 and 2 show typical secondary and tertiary responses to RS EOR, respectively.

Residual Oil Saturation Determination for EOR Projects in Means Field, a Mature West Texas Carbonate Field

Summary The technical success of an enhanced oil recovery (EOR) project depends on two main factors: first, the reservoir remaining oil saturation (ROS) after primary and secondary operations, and second, the recovery efficiency of the EOR process in mobilizing the ROS. These two interrelated parameters must be estimated before embarking on a time-consuming and costly process for designing and implementing an EOR process. The oil saturation can vary areally and vertically within the reservoir, and the distribution of the ROS will determine the success of the EOR injectants in mobilizing the remaining oil. There are many methods for determining the oil saturation (Chang et al. 1988; Pathak et al. 1989), and these include core analysis, well-log analysis, log/inject/log (LIL) procedures (Richardson et al. 1973; Reedy 1984), and single-well chemical tracer tests (SWCTT) (Deans and Carlisle 1986). These methods have different depths of investigation and different accuracies, and they all provide valuable information about the distribution of ROS. No single method achieves the best estimate of ROS, and a combination of all these methods is essential in developing a holistic picture of oil saturation and in assessing whether the oil in place (OIP) is large enough to justify the application of an EOR process. As Teletzke et al. (2010) have shown, EOR implementation is a complex process, and a staged, disciplined approach to identifying the key uncertainties and acquiring data for alleviating the uncertainties is essential. The largest uncertainty in some cases is the ROS in the reservoir. This paper presents the results from a fieldwide data acquisition program conducted in a west Texas carbonate reservoir to estimate ROS as part of an EOR project assessment. The Means field in west Texas has been producing for more than the past 75 years, and the producing mechanisms have included primary recovery, secondary waterflooding, and the application of a CO2 EOR process. The Means field is an excellent example of how the productive life and oil recovery can be increased by the application of new technology. The Means story is one of judicious application of appropriate EOR technology to the sustained development of a mature asset. The Means field is currently being evaluated for further expansion of the EOR process, and it was imperative to evaluate the oil saturation in the lower, previously undeveloped zones. This paper briefly outlines the production history, reservoir description, and reservoir management of the Means field, but this paper concentrates on the residual oil zone (ROZ) that underlies the main producing zone (MPZ) and describes a recent data acquisition program to evaluate the oil saturation in the ROZ. We discuss three major methods for evaluating the ROS: core analysis, LIL tests, and SWCTT tests.

Alkaline/Surfactant/Polymer Flood: Single-Well Chemical-Tracer Tests - Design, Implementation, and Performance

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 130042, ’Alkaline/ Surfactant/Polymer Flood: Single-Well Chemical-Tracer Tests - Design, Im plement ation, and Performance,’ by S.N. Oyemade, S.A. Al Harthy, H.F. Jaspers, SPE, J. Van Wunnik, SPE, and A. de Kruijf, SPE, Petroleum Development Oman, and M. Stoll, SPE, Shell Technology Oman, prepared for the 2010 SPE EOR Conference at Oil &amp; Gas West Asia, Muscat, Oman, 11-13 April. The paper has not been peer reviewed. Studies of mature fields in Oman have shown that alkaline/surfactant/polymer (ASP) flooding can yield significant incremental recoveries compared with waterflooding. However, the technique has risks: poor injectivity of the ASP slug, effectiveness of reservoir sweep, formation of scale in the wells and facilities, and persistent emulsions in the produced fluids. Analysis of these risks highlighted the need for pilot testing. Introduction A study indicated that ASP flooding could increase recovery in several fields, ranging from heavy-oil sandstone fields in southern Oman to light-oil carbonate fields in northern Oman. Several key risks that must be mitigated include extent of desaturation by ASP, ASP stability, emulsion breaking, and scaling. Tests were planned to reduce these uncertainties before making the significant investments associated with full-field implementation. Reservoirs were identified that could benefit from enhanced-oil-recovery (EOR) methods such as steam, chemical, and gas. Bottle tests are a subset of the coreflood tests and check various combinations of EOR chemicals—particularly alkali, surfactant, and polymer. Chemical EOR floods have been implemented with different combinations such as alkali/surfactant, alkali/polymer, and surfactant/polymer. From the bottle tests, different concentrations of chemical combinations were tried in coreflood tests. The optimum recipe for each reservoir was identified by flooding cores from the reservoir with reservoir fluids and the chemical mixtures. Following the coreflood tests, several tests could be run to determine desaturation. The single-well chemical-tracer (SWCT) test was chosen as an efficient means of confirming the effectiveness of laboratory results at a larger scale (well) and in situ (reservoir). SWCT tests are nondestructive (i.e., after the production step, the formation is returned to its original condition), which allows oil-saturation measurements before and after an EOR injection from a single well. The objective of the ASP SWCT tests was to mitigate risks of recovery and injectivity on a well or single-reservoir level. Three fields were selected for the ASP SWCT testing. Two fields are sandstone, and the third is a carbonate. Field X has had active waterflood support for more than 10 years, while fields Y and Z have no waterflood support. Following the SWCT test, a continuous-injection-pilot test may be planned for one of the fields. Candidate Selection Wells were selected from each of the three fields. The candidate-selection procedure for one of the three fields (Field X) is detailed in the full-length paper. Field X had 123 oil-producing wells. The screening criteria included gross production rate, high permeability, high water cut, possibility to log the well, well shape and deviation, casing integrity, interval homogeneity, and lack of interference with neighboring wells.

Analysis of a Single-Well Chemical Tracer Test To Measure the Residual Oil Saturation to a Hydrocarbon Miscible Gas Flood at Prudhoe Bay

Summary In 1990, a single-well chemical tracer (SWCT) test was performed in Prudhoe Bay to measure the effective waterflood and miscible gasflood residuals over a 12 ft reservoir interval. This is believed to be the first such use of this technology for a hydrocarbon miscible gas. This paper describes how the usual SWCT design was modified to accommodate the miscible gas, the results of the SWCT, which indicate significantly higher residual oil saturation for miscible gasflood than expected from coreflood experiments, and the subsequent simulation of the test which has provided good agreement with the observed results. The paper shows, with compositional simulation support, that the high apparent residual oil saturation was a consequence of incomplete volumetric sweep by the miscible gas and draws on the experiences of this test to make recommendations for the design of future SWCT tests measuring residuals to gasflooding.

Chemical Tracer Studies To Determine Water Saturation at Prudhoe Bay

Summary The single-well chemical tracer (SWCT) method was used to measure resident water saturation in two wells in the Ivishak reservoir of the Prudhoe Bay field. The tests, performed in 1981, were in API Wells 406 and 488, both of which had been oil-base cored through the Ivishak. The results of the tracer test in Well API 406 were interpreted by conventional SWCT simulation procedures. A three-layer simulator model was used to match the tracer production profiles measured during the test. The average water saturation obtained from the simulator match was 16 ±3% PV, in good agreement with the Dean-Stark analysis of the oil-base cores. The tracer-test results from Well API 488 were more difficult to interpret because of the very low water saturation at this location in the Ivishak. The SWCT method requires a hydrolysis reaction to take place in the formation to produce a product tracer. In this case, the amount of water present was so small that very little product tracer was formed. The interpreted Sw for this well was 2 ±2% PV, again in reasonable agreement with the oil-base-core measured value of 3.8%.

Thermal Effects on Single-Well Chemical-Tracer Tests for Measuring Residual Oil Saturation

Summary The single-well chemical-tracer (SWCT) test for measuring residual oil saturation, Sσr, often involves injecting cool fluid containing a reactive tracer into a warm formation. The Sor estimation with this method depends on the separation between reactant and product tracers. Because the reaction rate is temperature-dependent, accounting for the thermal effects may be necessary to obtain reliable results. Two simulator models are normally used to interpret SWCT tests. The ideal model is used for relatively homogeneous sandstone formations. The pore-diffusion model is used for heterogeneous carbonate formations. Both models have now been solved with appropriate heat-balance equations. These nonisothermal models have been used to reinterpret several previously reported field tests. For the worst case, the estimated Sor value from the nonisothermal model is 5% PV higher than that from the isothermal model. Inequality conditions have been developed that divide the parameter space of SWCT tests into two regions, depending on the location of the temperature front relative to the tracer bank during the reaction period. In the "safe" region, the estimated Sor values from isothermal and nonisothermal models are essentially equal. The inequality conditions have been extended to include the effects of over-and underburden layers and intervening shales in layered systems.