La Cira Infantas is the oldest oil field in Colombia. It has approximately 100 years of production, and it is located in the Middle Magdalena Valley Basin, producing from a black oil multilayered and heterogeneous sandstone reservoir. Primary production began in 1918 until 1959 when the first water flooding process began. In 2005, Oxy Colombia and Ecopetrol initiated a joint venture of a new redeveloped water flooding process. Since the joint venture, the field has expanded to 400 patterns and 1,000 active producer wells, 95% of which are under a water flooding process. The redesign of the field considers 20-acre to 25-acre on average and 5-spot to 7-spot inverted patterns. Injector wells have a selective string completion, with mandrels and packers that allow having control on the vertical distribution of the volume of water per mandrel group. In order to monitor water flood performance in the field, a reservoir surveillance methodology, based on dimensionless variables, has been implemented.
The methodology was originally applied for a CO2 flood surveillance and was later extended to fit water flooding monitoring purposes. The paper presents the application of the dimensionless methodology, which allows the evaluation of water flood areas independently of their pattern configuration. This allows the comparison between patterns, sector or areas versus a theoretical ideal performance curve and quickly identify underperforming patterns in order to propose remedial actions.
The application of this methodology has opened new opportunities in the field including the identification of well candidates for chemical stimulation jobs and conformance jobs, isolation jobs in producer wells as well as pump upsize opportunities. Additionally, it has improved the technical evaluation of workover jobs. Because of this, in the last four years La Cira Infantas has extended its portfolio activity, executing over 400 workover jobs. More importantly, it has allowed the transfer of more than 20MMBO into PDP reserves, and the production of 3,000BOPD of incremental oil production per year since 2014.
This paper will provide an insight into the water flooding surveillance carried out in La Cira Infantas, which has proven to be very successful in Oxy's business units.
Wang, Yang (China University of Petroleum – Beijing and Pennsylvania State University) | Cheng, Shiqing (China University of Petroleum – Beijing) | Zhang, Kaidi (Lusheng Petroleum Development Co., Ltd, SINOPEC Shengli Oilfield Company) | Xu, Jianchun (China University of Petroleum – East China) | Qin, Jiazheng (China University of Petroleum – Beijing) | He, Youwei (China University of Petroleum – Beijing and Texas A&M University) | Luo, Le (China University of Petroleum – Beijing) | Yu, Haiyang (China University of Petroleum – Beijing)
Pressure-transient analysis (PTA) of water injectors with waterflood-induced fractures (WIFs) is much more complicated than hydraulic fracturing producers due to the variation of fracture properties in the shutting time. In plenty of cases, current analysis techniques could result in misleading interpretations if the WIFs are not well realized or characterized. This paper presents a comprehensive analysis for five cases that focuses on the interpretation of different types of pressure responses in water injectors.
The characteristic of radial composite model of water injector indicates the water erosion and expansion of mini-fractures in the inner region. The commonplace phenomena of prolonged storage effect, bi-storage effect and interpreted considerably large storage coefficient suggest that WIF(s) may be induced by long time water injection. Based on this interpreted large storage coefficient, fracture half-length can be obtained. In the meanwhile, the fracture length shrinks and fracture conductivity decreases as the closing of WIF, which has a considerable influence on pressure responses. Results show that the upward of pressure derivative curve may not only be caused by closed outer boundary condition, but also the decreasing of fracture conductivity (DFC). As for multiple WIFs, they would close successively after shutting in the well due to the different stress conditions perpendicular to fracture walls, which behaves as several unit slopes on the pressure derivative curves in the log-log plot.
Aiming at different representative types of pressure responses cases in Huaqing reservoir, Changqing Oilfield, we innovatively analyze them from a different perspective and get a new understanding of water injector behaviors with WIF(s), which provides a guideline for the interpretation of water injection wells in tight reservoirs.
Hosseininoosheri, P. (The University of Texas at Austin) | Hosseini, S. A. (The University of Texas at Austin) | Nunez-Lopez, V. (The University of Texas at Austin) | Lake, L. W. (The University of Texas at Austin)
The relative partitioning of CO2 during and after CO2 injection in a CO2-EOR process is affected by several parameters. While many geological properties cannot be changed in a specific hydrocarbon (HC) reservoir, it could be shown that an intelligent selection of CO2 injection strategy improves both the incremental oil recovery and CO2 storage capacity and security. Therefore, we investigated and discussed the partitioning of CO2 among different phases (oil, gas, and brine) after two well-known CO2 inejction schemes using field-scale compositional reservoir flow modeling in the SACROC (Scurry Area Canyon Reef Operators Committee) unit, Permian Basin. First, we used a high-resolution geocellular model, which was constructed from wireline logs, seismic surveys, core data, and stratigraphic interpretation. As the initial distribution of fluids plays an important role in CO2 partitioning, a comprehensive pressure-production history matching of primary, secondary, and tertiary recovery was completed. The hysteresis model was used to calculate the amount of CO2 trapped as residual. CO2 solubility into brine was verified based on previous experiments. The model results showed a new understanding of relative CO2 partitioning in porous media after a CO2-EOR process. We compared the contribution of CO2 trapping mechanisms and the sweep efficiency of Walter-Alternating-Gas (WAG) and Continous-Gas-Injection (CGI). We found that WAG injection showed a significantly superior behaviour over CGI. WAG not only decreased the amount of mobile CO2 (structural trapping), but also resulted in a competitive incremental oil recovery in comparison with CGI. Thus, clearly WAG injection ispreferred as it strongly enhances CO2 storage efficiency and containment security. The present work provides valuable insights for optimizing oil production and CO2 storage in carbonate reservoirs like SACROC unit. In other words, this work helps decision makers to set storage goals based on optimized project risks.
A polymer pilot in the 8 TH reservoir in Austria showed promising results. The Utility Factors were below 2 of kg polymer injected / incremental barrel of oil produced (polymer cost are 2 – 4 USD/kg). Furthermore, substantial incremental oil was produced which might result in economic field implementation. The results triggered the planning for field implementation of polymer flooding.
To optimize the economics of field implementation, a workflow was chosen ensuring that the uncertainty was covered. 1200 geological models were generated covering a variety of different geological concepts. These geological models were clustered based on the dynamic response into 100 representative geological realizations and then used for history matching.
For infill drilling, probabilistic quality maps can be used to find locations. However, injection and production well optimization is more challenging. Introducing probabilistic incremental Net Present Value (NPV) maps allows for selection of locations of injection and production well patterns.
The patterns need to be optimized for geometry and operating parameters under uncertainty. The geometry was optimized in a first step followed by operating parameter optimization. In addition, injectivity effects of vertical and horizontal wells due to the non-Newtonian polymer rheology were evaluated. The last step was full-field simulation using the probabilistic NPV map, optimized well distance and operating parameters.
The resulting Cumulative Distribution Function of incremental NPV showed a Probability of Economic Success (PES) of 91 % and an Expected Monetary Value of 73 mn EUR.
A miscible injectant was used in a single injection well pilot in the Yates field to mobilize remaining oil in the gas cap and accelerate gravity drainage. Nitrogen, CO2 and recycled gas injection, all immiscible with Yates oil due to low original and current reservoir pressure, have been used historically to assist the gas-oil gravity drainage (GOGD) development. The result of immiscible injection has been a lowering of the gas-oil contact, a thinning of the oil column, and leaving a remaining oil saturation in the gas cap of up to 40 percent. A hydrocarbon mixture rich in ethane and propane and miscible with Yates oil was injected in a CO2 injector for six months after which the well was returned to pure CO2 injection.
Data collection during the pilot included repeat saturation logging of a newly drilled observation well, well tests of nearby horizontal producers, frequent gas and oil sampling, and chromatographic analysis. Phase behavior PVT experiments were also conducted which confirmed miscibility of the injectant and improvement over CO2 injection. Numerical simulation of pilot performance was also used as part of the interpretation.
Pilot results to date show a doubling of oil rate at peak over base oil decline, breakthrough in horizontal producers within 3-5 months matching an a priori prediction from numerical simulation, 10 percent reduction in oil saturation in the target interval in the gas cap, and the return of two wells to continuous production after having been shut-in due to high gas-oil ratios. Early interpretation of pilot results showed that most of the incremental oil and back produced enriched hydrocarbons came from one well. During the follow-up CO2 injection phase, one of the horizontal wells completed in the gas cap (unlike other pilot producers), was redrilled deeper into the oil column to improve the pilot areal and vertical sweep.
The pilot design, results, and interpretation will be discussed. Results from the pilot will be used to support evaluation of a field wide development, which could lead to substantial incremental reserves and extension of the field life.
Carbon dioxide (CO2) flooding is a mature technology in oil industry, which finds broad attention in oil production during tertiary oil recovery (EOR). After five decade’s developments, there are many successful reports for CO2 miscible flooding. However, operators recognized that achieving miscible phase is one of big challenge in fields with extremely high minimum miscible pressure (MMP) after considering the safety and economics. Compared with CO2 miscible flooding, immiscible CO2 flooding demonstrates the great potentials under varying reservoir/fluid conditions. A comprehensive and high-quality data set for CO2 immiscible flooding are built by collecting various data from books, DOE reports, AAPG database, oil and gas biennially EOR survey, field reports and SPE publications. Important reservoir/fluid information, operational parameters and project performance evaluations are included, which provides the basis for comprehensive data analysis. Combination plot of boxplot and histogram are generated, where boxplots are used to detect the special cases and to summarize the ranges of each parameter; histograms display the distribution of each parameter and to identify the best suitable ranges for propose guidelines.
Results show that CO2 immiscible flooding could recover additional 4.7 to 12.5% of oil with average injection efficiency of 10.07 Mscf/stb; CO2 immiscible technique can be implemented in light/medium/heavy oil reservoirs with a wide range of net thickness (5.2 - 300 ft); yet in heavy oil specifically reservoir (oil gravity <25 °API) with thin layer (net thickness< 50 ft) is better.
We present the first comprehensive experimental evaluation of CO2 EOR in organic rich shale. Experiments in preserved core demonstrated the potential of CO2 to extract the naturally occurring oil in organic rich shale reservoirs, whereas tests in re-saturated core plugs were used to compute accurate recovery factors, and evaluate the effect of soak time, operating pressure, and the relevance of slim-tube MMP on recovery. 18 core-flooding experiments were conducted in sidewall cores from different shale plays.
The cores re-saturated with crude oil, were first cleaned by Dean-Stark extraction, and submitted to porosity and compressibility determination. The re-saturation, confirmed by CT-scanning, was attained by aging the core plugs at high pressure for two to four months. In all experiments, glass beads surrounding core samples were used to simulate the proppant and physically recreate in the laboratory a hydraulic fracture connected to the shale matrix. The slim-tube MMP was measured with CO2, and core-flooding experiments were performed below, close to, and above the MMP. The displacement equipment was coupled to a medical CT-scanner that enabled us to track the changes in composition and saturation taking place within the shale cores during the experiments. Continuous CO2 injection and huff-and-puff were evaluated using soak time from zero to 22 hours. Fixed reservoir temperature was used in all the experiments.
Recovery factors ranged from 1.7 to 40%. The wide variation was the result of different experimental conditions for pressure and soak time. Both operational parameters were found to significantly affect the recovery. Increasing soak time at constant pressure consistently resulted in significant increase in recovery. The increase varied from 78 to 464% for different pressures and oil composition. Similarly, increasing operating pressure at constant soak time resulted in significant increase in recovery factor from 44 to 338% depending on soak time and oil composition. Unlike the typical response during CO2 EOR in conventional rocks, in organic rich shale, further pressure increases beyond the slim-tube MMP continued to increase the recovery factor significantly. In all runs, almost all oil recovery occurred within three days from the start of the experiment, and in all huff-and-puff tests the highest rate of recovery was observed in the first cycle, implying oil recovery with CO2 is a fast process, in comparison to oil re-saturation of the samples which occurs at a significantly slower rate.
This investigation demonstrates CO2 EOR is a technically feasible method to extract significant amounts of crude oil from organic rich shale reservoirs and it provides operational understanding of how to manage pressure and soak time to maximize recovery. The recovery factors obtained in this investigation, in the context of the vast reserves of crude oil contained in organic rich shale, can sustain a second shale revolution and further capitalize oilfield infrastructure.
Recently, the miscible CO2-EOR tertiary process used in the main pay zone (MP) of suitable reservoirs has broadened to include exploitation of the underlying residual oil zone (ROZ) where a significant amount of oil may remain. The objective of this study is to identify the ROZ and to assess the remaining oil in a brownfield ROZ by using core data and conventional well logs with probabilistic and predictive methods.
Core and log data from three wells located in the East Seminole Field in Gaines County, Texas, were used to identify the MP and ROZ in the San Andres Limestone, and to predict oil saturations. The core measurements were used to calculate probabilistic in-situ oil saturations within the MP and the ROZ as a function of depth. Well logs, in combination with core data and calculated saturations, on the other hand, were used to develop two expert systems using artificial neural networks (ANN); one to identify the ROZ and MP, and the other to predict oil saturation. These systems were also supported by a classification and regression tree (CART) analysis to delineate the rules that lead to classifications of zones.
Results showed that expert systems developed and calibrated by combining core and well log data can identify MP and ROZ with a success score of more than 90%. Saturations within these zones can be predicted with a correlation coefficient of around 0.6 for testing and 0.8 for training data. The analyses showed that neutron porosity and density well log readings are the most influential ones to identify zones in this field and to predict oil saturations in the MP and ROZ. To explain the relationships of input data with the results, a rule-based system was also applied, which revealed the underlying petrophysical differences between MP and ROZ.
This new predictive approach using machine learning techniques, could potentially address the challenges that previous studies have come up against in defining the ROZ within the formation and quantifying remaining oil saturations. The method can potentially be applied to additional fields and help reliably identify the ROZ and estimate saturations for future resource evaluations.
This paper presents modeling CO2 enhanced oil recovery (EOR) flood performance through the application of dimensionless scaling for both forecasting and surveillance purposes. While the methodology has been used successfully for West Texas CO2 floods for more than two decades, a recent modification in the process enhances the certainty of forecasted tertiary response based on simulation and analog results. The primary focus of this paper is on how this new approach improves the use of analog or observed production history to develop more reliable forecasts for EOR processes. Business units favor analog methods since they are fast, adaptable and explicit.
Analog tertiary production response is the incremental oil production over an estimated base waterflood oil recovery. The original formulation, published in a different paper (
Fredriksen, S. B. (University of Bergen) | Alcorn, Z. P. (University of Bergen) | Frøland, A. (University of Bergen) | Viken, A. (University of Bergen) | Rognmo, A. U. (University of Bergen) | Seland, J. G. (University of Bergen) | Ersland, G. (University of Bergen) | Fernø, M. A. (University of Bergen) | Graue, A. (University of Bergen)
An integrated enhanced oil recovery (IEOR) approach is presented for fractured oil-wet carbonate reservoirs using surfactant pre-floods to alter wettability, establish conditions for capillary continuity and improve tertiary CO2 foam injections. Surfactant pre-floods, prior to CO2 foam injection, alter the wettability of fracture surface towards weakly water-wet conditions to reduce the capillary threshold pressure for foam generation in matrix and create capillary contact between matrix blocks. The capillary connectivity transmits differential pressure across fractures and increases both mobility control and viscous displacement during CO2 foam injection. Outcrop core plugs were aged to reflect conditions of an ongoing CO2 foam field pilot in West Texas. A range of surfactants were screened for their ability to change wetting state from oil-wet to water-wet. A cationic surfactant was the most effective in shifting the moderately oil-wet cores towards weakly water-wet conditions (from an Amott-Harvey index of - 0.56 ± 0.01 to 0.09 ± 0.02), and was used for pre-floods during IEOR. When applying a surfactant pre-flood in a fractured core system, 32 ± 4% points OOIP was additionally recovered by CO2 foam injection after secondary waterflooding. We argue the enhanced oil recovery is attributed to the surfactant successfully reducing the capillary entry pressure of the oil-wet matrix providing capillary continuity and enhancing volumetric sweep during tertiary CO2 foam injection.