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The single well chemical tracer (SWCT) test can be used to evaluate an Improved oil recovery (IOR) process quickly and inexpensively. The one-spot procedure takes advantage of the nondestructive nature of the SWCT method. The single-well (one-spot) pilot is carried out in three steps. First, Sor for the target interval is measured (see Residual oil evaluation using single well chemical tracer test. Then an appropriate volume of the IOR fluid is injected into the test interval and pushed away from the well with water.
In certain situations, it is necessary to obtain a reliable measurement for connate water saturation (Swc) in an oil reservoir. The single well chemical tracer (SWCT) method has been used successfully for this purpose. The SWCT method has been used successfully for this purpose in six reservoirs. The SWCT test for Swc usually is carried out on wells that are essentially 100% oil producers. The procedure is analogous to the SWCT method for Sor, taking into account that oil is the mobile phase and water is stationary in the pore space.
Paskvan, F.. (State of Alaska Department of Natural Resources Division of Oil and Gas) | Blas, P. San (State of Alaska Department of Natural Resources Division of Oil and Gas) | Young, J.. (State of Alaska Department of Natural Resources Division of Oil and Gas) | Bakun, F.. (State of Alaska Department of Natural Resources Division of Oil and Gas) | Carlisle, C.. (State of Alaska Department of Natural Resources Division of Oil and Gas) | Pope, G.. (State of Alaska Department of Natural Resources Division of Oil and Gas)
Abstract Single well chemical tracer tests were used to measure saturations and oil-water fractional flow accurately, quickly, and cost-effectively. The Aurora oil field in the Prudhoe Bay Unit, Alaska, was identified for fast-paced development leveraging existing facilities. A series of single well chemical tracer tests (SWTT) determined key volumetric and reservoir performance properties including: Initial oil saturation, Waterflood residual oil saturation, Miscible gas EOR residual oil saturation, and Waterflood water-oil fractional flow. The SWTT measurements of initial oil saturation, residual oil saturation to water, residual oil saturation to miscible gas, and oil-water fractional flow made during the initial field development in 2001 closely match current model parameters determined based upon 18 years of field history. Methods, Procedures, Process Given a fast development pace and relatively small field size, it was deemed impractical to collect low invasion core and perform expensive, complex, and time consuming special core analysis. Instead, a series of SWTT were performed on a single production well to determine key reservoir parameters within six months. This compares favorably to core acquisition and analysis which can take six times longer and cost ten times as much. Also, SWTT can be performed after a well is drilled and on production, so key tests can be performed without early, time-intensive special core analysis acquisition planning and rig time. Aurora production well S-104 was chosen as the key data collection well to describe Aurora field. The well was conventionally cored and had a full suite of open hole logs including nuclear magnetic resonance and focused micro resistivity. This well was an ideal candidate for a SWTT as it had a good quality cement job, no water or gas injection, a detailed near wellbore reservoir description, and the well would produce to surface with gas lift. The SWTTs were performed over a 30-foot perforated interval. A typical SWTT involves tracer injection, shut-in time, then production flowback. No downhole interventions were needed since SWTT are performed using readily transportable surface equipment like chemical injection pumps and well tracer sampling and measurement equipment including a gas chromatograph. Results, Observations, Conclusions Connate water saturation was lower than expected (13% ±2), increasing the estimated oil in place and calibrating the well log water saturation log model and reservoir model saturation-height function. Due to increased initial oil saturation proved by the SWTT, additional wells were justified in the southern portion of the field which added an estimated 2.5 million barrels of recovery. The waterflood residual oil saturation was higher than expected (30% ±2) indicating a more oil-wet system than previously assumed. The oil-water fractional flow data also indicated a more oil wet relative permeability curve than estimates from available analog curves. Finally, the miscible gas EOR test demonstrated miscibility and enhanced oil recovery in-situ by measuring very low residual oil saturation (4.5% ±2) to miscible injection gas. Novel/Additive Information This is the world's first successful SWTT water-oil fractional flow measurement. If data collection had included downhole pressure gauges, the test would have also measured relative permeability endpoints. The Aurora SWTT program provides an innovative solution to a classic challenge: Accurately determining key reservoir properties in a timely and cost-effective way. Reservoir simulation using SWTT results match 18 years of field performance, demonstrating the accuracy of SWTT measurements.
Abstract Obtaining reliable production surveillance data is not always achievable with all completion types. Two heavy oil production wells in the Nikaitchuq field in Northern Alaska hosted such challenges. The wells do not flow naturally and ESP's were chosen as the artificial lift (AL) method, thus eliminating the option of applying conventional flow profiling techniques such as production logging tools (PLT). Permanent chemical intelligent tracer systems were installed to monitor inflow distribution and water breakthrough along the long horizontal production intervals. The nature of heavy oil fields in this area require long, horizontal production wells with adjacent injectors to drive waterflood support. Lateral production conformance in this area was unknown or could not be definitively confirmed. A means to understand inflow performance along laterals in order determine appropriate lateral length and optimize waterflood design was needed. Early water breakthrough due to uneven water front and possible matrix bypass has previously been experienced in nearby, analogous fields. A means to determine the general location of water breakthrough was also desired. Oil and water intelligent tracers were chosen to provide the required information to enhance pressure management and waterflood techniques. These intelligent tracers were placed strategically along the lateral in multiple development production wells. With this knowledge in hand, other production optimization tools such as ICD's, DTS and zonal isolation packers can be assessed to help effectively manage the waterflood. The intelligent tracer systems are designed to release unique tracer chemicals when exposed to the corresponding target fluid, i.e. oil and water contact triggers intelligent oil and water tracer release respectively. The tracer transient signatures are interpreted to assess the type, location, and quantity of fluid flow along the lateral. Re-start monitoring campaigns have been conducted for three wells during dry oil production. The data interpretation confirmed toe production in two of the wells. Quantitative estimates of inflow distribution along the producing sections were made for all wells. Introduction The Nikaitchuq field is located on the North Slope of Alaska, west of Prudhoe Bay (Figure 1). The field consists of an onshore site (Oliktok Point, OPP), an offshore drill site (Spy Island Drillsite, SID), a processing facility and associated infrastructure. Nikaitchuq has been producing since January 30, 2011. The Nikaitchuq project is a 52-well development of the Schrader Bluff reservoir which contains viscous oil in unconsolidated sand. The API of the crude oil is approximately 18.7° on average. The reservoir vertical depth is approximately 3,500 to 4,000 ft TVD. The development was planned as a line drive waterflood utilizing extended reach horizontal laterals with measured depth ranging from 15,000 to 22,000 feet. A complex reservoir monitoring and control strategy was implemented in the field development to understand the interaction between injection and production wells along the length of the extended lateral sections. Monitoring and control for injection wells include fiber optic distributed temperature sensing with pressure and temperature gauges placed in selected locations. Passive injection control devices are also placed in the injection wells, which include a feature to control water injection at each device location. Due to the inability of the production wells to flow naturally, electric submersible pumps (ESP) were chosen as the preferred method for artificial lift. This configuration does not allow for conventional production logging; therefore, a long term solution was required that did not require well intervention. Permanent chemical production tracers were chosen as the method for production inflow monitoring along the length of the laterals and are an integral part of the monitoring and control strategy. Three of the Spy Island Producers (SP) equipped with intelligent inflow tracers will be discussed in this paper; SP16-FN3, SP33-W3, and SP10-FN5.
Abstract The streamline-based tracer model has been successfully deployed to history match and predict miscible and immiscible Water Alternating Gas (WAG) processes at the field scale. The tracer model is a simplified method for the three-phase WAG process, and is computed parallel to the traditional streamline waterflood model. This paper provides an overview to illustrate the relevant concepts and applications of the streamline-based tracer model. A Prudhoe Bay example of the vertical Miscible Injection Stimulation Technique (MIST) is presented to demonstrate and to verify the field use of the tracer model. Introduction WAG injection has been recognized as an effective improved oil recovery (IOR) procedure and is widely applied to enhance trapped oil production in reservoirs such as in Prudhoe Bay. Our knowledge of the controlling physics of WAG injection in the field can be limited. WAG injection is a complex multiphase process influenced by important factors such as geologic heterogeneity, gravity, phase interactions resulting in changes in mobility, among many others. Historical efforts to develop simulation tools for WAG processes to history match and to predict field scale IOR operations have proven to be difficult yet challenging. Accurate modeling requires fine-scale, three-dimensional, fully compositional models that simulate rapid gas movements in a reservoir containing possibly thousands of wells. Such models can be very CPU-intensive for real reservoir management and decision-making. With the continuing development of streamline technology, it is possible to construct a field-scale, 3D, compositional, three-phase streamline model to simulate the dominant physics of the WAG process, although CPU times can still be large. The streamline model used in this paper was designed when the streamline simulator could only support two-phases. The tracer model is therefore an add-on to a traditional two-phase (oil and water), front-tracking reservoir simulator, leading to speed-up and flexibility in simulating the WAG IOR process. Future enhancements to the tracer model will utilize more of the current simulator's 3D and three-phase capabilities. This tracer add-on model was designed to simulate the WAG injection process in a simplified two-phase setting. Highly complex, faulted grids can be modeled and large times step can be taken with minimal numerical dispersion. As wellrates change, front locations are mapped and propagated along updated streamlines. This approach takes advantage of minimal numerical dispersion, which plays havoc with finite-difference prediction alternatives. This leads to the possibility of running large fine-scale models very quickly. The tracer model consists of two independent displacement processes propagating in parallel along each streamline. The first process is the traditional waterflood to reduce oil saturation to waterflood residual level; the second process is the MWAG to further reduce oil saturation to below waterflood residual level. An important feature of the streamline-based tracer model is the explicit modeling of IOR oil (i.e., the incremental oil recovery over waterflood) spatial distribution. In this paper, we use the term IOR to strictly refer to the incremental oil from the WAG injection operation in the field. The IOR displacement process is mimicked by the simplified movement of solvent and IOR tracers, each tracer flows along the existing streamline (for oil and water) at a user-specified multiple (accessible pore volume factor) of the Darcy velocity. This explicit approach allows streamlines to reveal WAG-injector/IOR-producer pairs and clusters dynamically.
Cockin, A.P. (BP Exploration Co. Ltd.) | Malcolm, L.T. (BP Exploration Co. Ltd.) | McGuire, P.L. (Arco Alaska Inc.) | Giordano, R.M. (Arco Exploration & Production Technology) | Sitz, C.D. (Chemical Tracers, Inc.)
Abstract In 1990 a single well chemical tracer (SWCT) test was performed in Prudhoe Bay to measure the effective water flood and miscible gas flood 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 for the miscible gas part were significantly higher than miscible gas coreflood residuals, and the subsequent simulation of the test which has provided good agreement with the observed results. The paper explains, with simulation support, what caused the measured residuals to be higher than expected, and draws on the experiences of this test to make recommendations for the design of future SWCT tests measuring residuals to gas flooding. P. 61
Direct reservoir formation water extractions on more than 8,000 plugs from 27 wells cored with oil-base mud were used to determine water saturation (S,) in Prudhoe Bay field, Alaska. A question and answer format is used to review the abundant and compelling evidence from the multicompany research program that established their validity. The main criticism of oil-mud core Sw is that water might be lost while the core is cut and brought to the surface. This criticism is easily asserted but difficult to disprove. New technology coring bits made possible the recovery of cores that have no invasion at their centers. Photographs clearly show these uninvaded centers. Invaded and uninvaded cores were found to have the same S, values. From pressure-retained cores, it was determined that depressurization did not cause any measurable water loss. Like most reservoirs, Prudhoe Bay has a very long transition zone and, in all but the lowest section, the evidence demonstrates that the core S, values are valid. S, values at Prudhoe Bay vary from 1% to more than 50%. The oil-mud core S, values were used to calibrate S, values from the resistivity logs and the Archie equation by adjusting the saturation exponent (n) value. This calculated n varied from 1.7 to 3.1. Three indirect S, evaluation methods (log, capillary pressure, and chemical tracer-test analyses) give results consistent with the core Sw values after painstaking work to understand their many variables. For example, the reservoir water salinity varies from 6 to 45+ g/L of C1-, and Rw varies from 0.1 3 to 0.72 ohm-m at 68"F, when the aquifer is 0.34 ohm-m. Standard laboratory measurements of n have large uncertainties because of the difficulty of reproducing both the reservoir water saturation and its distribution. The uncertainties of S, from oil-mud cores and the Archie equation are evaluated by partial differential analysis. The practical importance of standard log interpretation is not diminished by this work. This paper, and the team''s other publications, show that a significantly more accurate S, measurement is available when the extra effort is justified. Subsequent work elsewhere with oil-emulsion mud has provided cores of equal validity to those in Prudhoe Bay field. Every time hydrocarbon-zone cores are cut in oil-base muds of any type it is clearly worthwhile to obtain good quality core S, measurements.
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%. Sw Determinations in the Ivishak Introduction. The estimation of hydrocarbon pore volume, VpHC in the Ivishak (commonly called the Sadlerochit) reservoir of the Prudhoe Bay field used the general relationship given in Eq. 1.Equation 1 Because Sw was suspected to vary considerably within the oil zone, accurate estimation of VpHC demanded good measurements of Sw at a reasonable number of locations in the reservoir. For reasons discussed by McCoy and Grieves, electric log accuracy was inadequate in some parts of the Sadlerochit. The primary method chosen to measure Sw was Dean-Stark analysis of samples from cores taken with oil-base drilling fluids. As an independent confirmation, in-situ measurements of Sw in two of the oil-base-cored wells by use of the SWCT method were performed. Tracer Methods for Measuring S w . The SWCT method was originally developed by Deans and Deans et al. to measure residual oil saturation, Sor, after waterflooding. Since 1968, this technique has been used in more than 200 sandstone and carbonate formations. Well-to-well tracer methods that use the same principles have been less frequently reported. Operational considerations make a single-well procedure much more practical. As practiced, the SWCT method measures an average residual saturation over a relatively large volume of pore space. Typical depth of investigation is 10 to 20 ft away from the wellbore, which should be beyond the region of alteration caused by drilling and completion operations.