Single Well Chemical Tracer Tests Research Articles

Single-Well Chemical-Tracer Modeling of Low-Salinity-Water Injection in Carbonates

Summary The interest in low-salinity-water injection (LSWI) compared with seawater injection or high-salinity-produced-brine injection is increasing in both laboratory and field tests. The single-well chemical-tracer test (SWCTT) is also becoming increasingly popular as an in-situ test to assess the reduction in oil saturation caused by an enhanced-oil-recovery (EOR) process. Hence, accurate modeling of SWCTTs is essential. In this paper, modeling and simulation of the SWCTT of LSWI in a carbonate reservoir is investigated by use of the UTCHEM reservoir simulator, a nonisothermal, 3D, multiphase, multicomponent, chemical compositional simulator developed at the University of Texas at Austin (UTCHEM 2011). Both radial- and Cartesian-grid models are set up for a field-scale pilot by use of measured rock and fluid data of a Middle Eastern reservoir. Tracer reactions and the empirical LSWI model implemented in UTCHEM are used to estimate residual oil saturation (ROS) as a result of LSWI. Two approaches are used to estimate ROS to LSWI, including analytical and numerical methods. Results show that both approaches give consistent values for ROS for homogeneous radial- and Cartesian-grid models. The two approaches were inconsistent for the multilayer radial model, which highlights the necessity of the use of numerical approaches for layered reservoirs. The Cartesian-grid model was used to investigate the effect of heterogeneity on SWCTT results, where a new numerical approach is proposed for estimating ROS. This finding validates the approach used and the implementation of both tracer reactions and the LSWI model in UTCHEM. The proposed approach can now be used to estimate ROS of the SWCTT for reservoirs with different degrees of heterogeneity, which provides a clear insight into reservoir performance before planning multiwell demonstration pilots.

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.

The Design and Execution of an Alkaline/Surfactant/Polymer Pilot Test

Summary A tertiary alkaline/surfactant/polymer (ASP) pilot flood was implemented during 2010 in the Illinois basin of the US, and is continuing currently. With initial discovery of the Bridgeport sandstone formation in the early 1900s and more than 60 years of waterflooding, the pilot was designed to demonstrate that ASP flooding could produce sufficient quantities of incremental oil to sanction a commercial project. Laboratory experiments, including corefloods, were performed to determine the optimal chemical formulation for the pilot and to provide essential parameters for a numerical-simulation model. Polymer-injectivity tests, single well chemical tracer tests (SWCTTs), and an interwell-tracer-test (IWTT) program were all performed to prepare for and support a full interpretation of the pilot results. A field laboratory was run through the duration of the pilot to monitor the quality of the injection and production fluids, which turned out to be critical to the success of the pilot. We present the results and interpretation of the ASP pilot to date, the challenges faced during the project, and the lessons learned from the field perspective.

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 & 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.

Snorre Low-Salinity-Water Injection—Coreflooding Experiments and Single-Well Field Pilot

Summary Low-salinity (lowsal) waterflooding has been evaluated for increased oil recovery (IOR) at the Snorre field. Coreflooding experiments and a single-well chemical tracer-test (SWCTT) field pilot have been performed to measure the remaining oil saturation after seawaterflooding and after lowsal flooding. The laboratory coreflooding experiments conducted at reservoir and low-pressure conditions involved core material from the Upper and Lower Statfjord and Lunde formations. The core material from the Statfjord formations gave incremental recovery in the order of 2% of original oil in place (OOIP) by injection of diluted seawater. Similar amounts were produced during following NaCl-based lowsal injections. The same trend was observed in the high- and low-pressure experiments. No significant response to lowsal flooding was observed for Lunde cores. No response was normally observed during alkaline injection. The SWCTT field pilot was carried out in the Upper Statfjord formation. The average oil saturations after seawater injection, after lowsal seawater injection, and after a new seawater injection were determined; no significant change in the remaining oil saturation was shown. The measured in-situ value of remaining oil saturation after seawaterflooding was in agreement with previous special core analysis (SCAL) experiments. The measured effect of tertiary lowsal flooding from core experiments was in agreement with the SWCTT. Both measurements indicated only low or no effect from lowsal injection. It has been suggested that lowsal flooding has a potential for improved oil recovery in all clayey sandstone formations containing crude oil. The results from this work indicate that the initial wetting condition is a crucial property for the effect of lowsal injection.

Modeling Low-Salinity Waterflooding

Summary Low-salinity waterflooding is an emerging enhanced-oil-recovery (EOR) technique in which the salinity of the injected water is controlled to improve oil recovery vs. conventional, higher-salinity waterflooding. Corefloods and single-well chemical-tracer tests have shown that low-salinity waterflooding can improve basic waterflood performance by 5 to 38%. This paper describes a model of low-salinity flooding that can be used to evaluate projects; shows the implications of that model and demonstrates its use to represent corefloods, single-well tests, and field-scale simulations; and gives insight into the reservoir engineering of low-salinity floods. The model represents low-salinity flooding using salinity-dependent oil/water relative permeability functions resulting from wettability change. This is similar to other EOR modeling, and conventional fractional-flow theory can be adapted to describe the process in 1D for secondary and tertiary low-salinity waterflooding. This simple analysis shows that while some degree of connate-water banking occurs, it need not hinder the process. Mixing of injected water with in-situ water delays the attainment of low salinity, potentially preventing attainment of low salinity all together if very small slugs of low-salinity water are used. This paper demonstrates the importance of mixing to modeling of low-salinity flooding and suggests addressing it in engineering calculations. Care must be taken in representing mixing appropriately in interpreting data and in constructing models. The use of numerical dispersion to represent physical dispersion in 1D, radial, and pattern simulations of this process is demonstrated (i.e., coarse-grid simulations are shown to give the same result as fine-grid simulations with an appropriately large physical dispersion). In many applications, the fine-grid simulation necessary to represent appropriate levels of dispersion is not practical, and pseudoization is necessary. We demonstrate that this can be achieved by changing the salinity dependence and shapes of relative permeability curves.

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.