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.
Åsen, Siv Marie (UiS, IRIS and The National IOR Centre of Norway) | Stavland, Arne (IRIS and The National IOR Centre of Norway) | Strand, Daniel (IRIS and The National IOR Centre of Norway) | Hiorth, Aksel (UiS, IRIS and The National IOR Centre of Norway)
In this work, we challenge the common understanding that mechanical degradation takes place at the rock surface or within the first few mm. The effect of core length on mechanical degradation of synthetic EOR polymers was investigated. We constructed a novel experimental set-up for studying mechanical degradation at different flow rates as a function of distances travelled. The set-up enabled us to evaluate degradation in serial mounted core segments of 3, 5, 8 and 13 cm individually or combined. By recycling we could also evaluate degradation at effective distances up to 20 m. By low rate reinjecting of polymers previously degraded at higher rates, we simulated the effect of radial flow on degradation.
Experiments were performed with two different polymers (high molecular weight HPAM and low molecular weight ATBS) in two different brines (0.5% NaCl and synthetic seawater).
In linear flow at high shear rates, we observed a decline in degradation rate with distance travelled, but a plateau was not observed. Even after 20 m there was still some degradation taking place. The molecular weight (MW) of the degraded polymer could be matched with a power law dependency,
We conclude that in linear flow, the mechanical degradation depends on the core length. However, in radial flow where the velocity decreases by length, the mechanical degradation reaches equilibrium with no further degradation deeper into the formation.
For the experiments where we evaluated degradation over large distances at high shear rates, we observed a decline in degradation rate with distance travelled, but we could not conclude that we reached a plateau. Even after 20 m there is still some degradation taking place. It is important to consider this knowledge when interpreting core scale experiments. However, the observed degradation is associated with high-pressure gradients, in the order of 100 bar/meter, which at field scale is not realistic.
We confirmed previous findings; degradation depends on salinity and molecular weight. Results show that in all experiments with significant degradation, most of the degradation takes place in the first core segment. Moreover, the higher the shear rate and degradation, the higher is the fraction of degradation that occurs in the first core segment.
Over the last decade, unconventional resources like the Bakken formation have revolutionized the petroleum industry, but they have only produced by primary mechanisms, and recovery factors have remained low. The need for IOR processes is clear, but there has only been minor work in this area and no commercial field applications. Flow simulation models can be used to test different methods without interrupting field operations, but models have had a poor track record for unconventional IOR, partly because there is little field injection information to validate the models. In this work, we history matched the model to an IOR injection pilot location in Mountrail County, North Dakota that included both water and gas injection tests.
A county sized geologic model was previously constructed based upon available core, log and geologic information. The model allows for easy extraction of smaller segments for flow simulation. For the current study, a segment around the pilot injection area was isolated. The injection well and two offset producing wells were included in the model. Fluids were added into the model based on a nearby PVT report, and the hydraulic fracturing was captured with a dual permeability grid. The model was matched to the historical production and injection data. At the offset wells, breakthrough times, water cuts and gas oil ratios were also reproduced by changing the fracture and matrix properties.
By matching the injection data, the interwell connectivity is reproduced, which should improve predictions from the model. Various situations were then tested with the model including both gas and water injection scenarios. In the actual field pilot, gas was only injected for two months in the injection well, and there was only a minor response. In one scenario, therefore, we injected into all three wells in a huff-n-puff manner for ten years, and the results showed significant additional oil recovered – 30% more than the primary recovery. In other scenarios, water was injected in both a continuous and huff-n-puff manner. The continuous case had early breakthrough and poor sweep, but the huff-n-puff injection case indicated that oil rates would increase almost as much as the best gas injection cases.
This work shows that by reproducing the field injection data in unconventional reservoirs, more realistic models are created. We evaluated a large number of scenarios, and some of them did not show any increase in oil production, but the models that did show an increase helped us identify IOR techniques that have a better chance of success in the Bakken, which will improve designing the much needed next generation of field pilot tests.
Leon, J. M (Ecopetrol, S.A) | Izadi, M. (Ecopetrol, S.A) | Castillo, A. (Ecopetrol, S.A) | Zapata, J. F. (Ecopetrol, S.A) | Chaparro, C. (Ecopetrol, S.A) | Jimenez, J. (Ecopetrol, S.A) | Vicente, S. E. (Ecopetrol, S.A) | Castro, R. (Ecopetrol, S.A)
The Dina Cretaceous field, operated by Ecopetrol S.A., is located in the Upper Magdalena Valley (UMV) Basin in Colombia. The field discovered in 1969, reaching maximum primary oil rate of 6,500 BOPD in May 1980. Secondary recovery mainly by peripheral water injection started in 1986, achieving a maximum production of 9,850 BOPD in January 1988. Subsequently, water production has increased rapidly accompanied by declining oil production, due primarily to reservoir heterogeneity and an unfavorable mobility ratio. The oil recovery factor as of October 2017, as a percentage of OOIP, is estimated to be approximately 33% at a current water cut of about 97%.
Ecopetrol S.A in 2009, began to look for new development strategies that would allow optimizing the oil recovery for this asset. Several IOR/EOR technologies were screened to reduce water production and increase sweep efficiency. Polymer gels ("Conformance treatments"), polymer flooding and cross-linked polymer also known as Colloidal Dispersion Gels (CDG) are some of the technologies most commonly used during the last few decades for this purpos. Based on screening study, detailed production and injection data analysis, water channeling, reservoir heterogeneity, adverse mobility ratio, laboratory evaluation and simulation results, the cross-linked polymer systems (CDG) were implemented in four patterns between 2011 and 2015. This would allow to increase the volumetric sweeping efficiency both for mobility control, in-depth conformance control and leading to viable project both technically and economically.
This paper presents the implementation and results of the injection of cross-linked polymer systems in the Dina Cretaceous field. A summary of the maturation process is presented, from conceptual design, experimental evaluation, engineering analysis, numerical simulation, pilot execution, process monitoring and field expansion strategy, as well as the results obtained in the pilot.
The results of the pilot were satisfactory both technically and economically and lead to a new development plan for the field. This new plant is focused on the optimization of the waterflood, pattern reconfiguration, infill drilling, selective injection, and improving the sweep efficiency through the injection of cross-linked polymer across the field in 11 more patterns.
Patil, P. D. (The Dow Chemical Company) | Knight, T. (The Dow Chemical Company) | Katiyar, A. (The Dow Chemical Company) | Vanderwal, P. (The Dow Chemical Company) | Scherlin, J. (Fleur De Lis Energy LLC) | Rozowski, P. (The Dow Chemical Company) | Ibrahim, M. (Schlumberger) | Sridhar, G. B. (Schlumberger) | Nguyen, Q. P. (The University of Texas at Austin)
This paper summarizes the overall response from the CO2-foam injection in the Salt Creek field, Natrona County, Wyoming. Conformance control of CO2 by creating foam between supercritical CO2 and brine to improve the sweep efficiency is documented in this paper. The foam was implemented in an inverted fivespot pattern in the Salt Creek field where the second Wall Creek (WC2) sandstone formation is the primary producing interval, with a net thickness of about 80 ft and at a depth of approximately 2,200 ft. The initial phase of the foam pilot design involving identifying the pilot area, performing coreflood experiments, performaing dynamic reservoir simulation for history match, and forecasting with foam have been documented in the literature. As a part of the foam pilot monitoring, a gas tracer study was performed before and after the injection of foam in the reservoir. The initial planning, monitoring, and part of foam response is covered in earlier publications. The last surfactant injection in the field was in June 2016. This paper provides the complete analysis of the results from the foam pilot. The foam pilot was successful in demonstrating the deeper conformance control and improvement in sweep efficiency, which resulted in 25,000 bbl of incremental oil. Also overall, a 22% decrease in CO2 injection amount is realized due to better utilization of CO2 compared to the baseline.
After 6 years of continous polymer injection in El Corcobo Norte field, pilot's preliminar evaluation showed promising results. Although the evaluation is still ongoing, polymer technology economics look good enough to sustain a project expansion.
Located in the Neuquén Basin, El Corcobo Norte field is an unconsolidated, underpressurized, strongly water-wet sandstone reservoir, producing medium-heavy oil from the Centenario Formation. Reservoir drive is waterflood, which has been implemented since the beginning of the field's development. Up to date the field has more than 650 producers and 350 injectors, mostly developed under 20 acres, inverted 7-spot patterns. Main challenge for this field's operation is sand production and chanelling issues that leave bypassed or undrained oil zones.
Since 2008 EOR technologies were evaluated in order to increase ultimate recovery factor. As a results of this screening, polymer injection was chosen as the first candidate to test in the field. Polymer pilot design and execution was described in SPE 160078 ("Desing and Execution of a Polymer Injection Pilot in Argentina") and pilot preliminar evaluation was presented in SPE 181210 ("Evaluation of a Polymer Injection Pilot in Argentina").
Based on the pilot's learnings, an expansion project was designed to maximize the use of the available capacity and upscale polymer injection as efficiently as possible, considering field's current operational conditions.
The present article will focus on describing the upscale of the polymer pilot and the strategy to optimize the project's operation.