Andersen, Pål Østebø (Dept. of Energy Resources, University of Stavanger) | Lohne, Arild (The National IOR Centre of Norway, University of Stavanger) | Stavland, Arne (The National IOR Centre of Norway, University of Stavanger) | Hiorth, Aksel (Dept. of Energy Resources, University of Stavanger) | Brattekås, Bergit (Dept. of Energy Resources, University of Stavanger)
Capillary spontaneous imbibition of solvent (brine bound in gel) from formed polymer gel into an adjacent, oil-saturated porous medium was recently observed in laboratory experiments. Loss of solvent from the gel by spontaneous imbibition may influence the blocking capacity of the gel residing in a fracture, by decreasing the gel volume, and may contribute to gel failure, often observed in water-wet oil fields. Formed gel cannot enter significantly into porous rock, which has important implications for spontaneous imbibition: the gel particle network itself is not imbibed, and remains close to the rock matrix surface, while gel solvent can leave the gel and progress into the matrix due to capillary forces. Polymer gel is an inherently complex fluid and modelling of its behavior is, as such, complicated. Accurate description and quantification of gel properties and behaviour on the laboratory scale is, however, necessary to predict the performance of gel placed in an oil field, particularly in fractured formations. In this work, we present an original modelling approach, to simulate and interpret spontaneous solvent imbibition from Cr(III)-Acetate HPAM gel into oil-saturated chalk core plugs. A theory describing solvent flow within a gel network is detailed, and was implemented into an in-house simulator. Simulations of spontaneous imbibition from gel was performed, and compared to free spontaneous imbibition of water. A good overall match was achieved between experiments and simulations on the core scale, which validates the proposed gel model.
All Faces Open (AFO) and Two Ends Open - Free Spontaneous Imbibition (TEOFSI) boundary conditions were used in the experiments, and formed the basis for simulation. Spontaneous imbibition occurs at the core end faces that are open to flow and exposed to gel (different for the two boundary conditions). The gel surrounding the core was discretized and included as a part of the total grid to capture transient behavior. The surrounding gel is treated as a compressible porous medium where the gel's polymer structure constitutes the matrix having constant solid volume while the gel porosity is a function of pore pressure. The gel permeability is modelled as function of gel porosity using a Kozeny-Carman approach. The flow equations for the gel and core domains were solved simultaneously by implementing the proposed description into the core scale simulator IORCoreSim. Two properties were identified to control the transport of water from gel into the adjacent matrix: the permeability and compressibility of the gel. The flow of water from the gel was observed in simulations to occur in a transient manner, driven by the coupled gradients in gel fluid pressure and gel porosity, where the gel porosity initially decreases in a layer close to the core surface due to reduced aqueous pressure. Gel porosity continued to decrease in layers away from the core surface; the propagation rate was controlled by two main gel parameters: (i) Gel compressibility controlled the pressure gradient within the gel network, and the amount of water transported from the outer part of the gel towards the core surface to balance the pore pressure. (ii) Gel permeability limited how fast water could flow within the gel at a given pressure gradient, thus increasing the time scale of the overall imbibition process.
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.
Morales, Victor Alfonso (Occidental de Colombia LLC) | Ramirez, Leyla Kristle (Occidental de Colombia LLC) | Garnica, Sandy Vanessa (Occidental de Colombia LLC) | Rueda, Luz Adriana (Occidental de Colombia LLC) | Gomez, Vicente (Occidental de Colombia LLC) | Gomez, Adriana (Occidental de Colombia LLC) | Bejarano, Maria Angelica (Occidental de Colombia LLC) | Shook, G. Michael (Mike Shook & Associates)
La Cira Infantas is the oldest oil field in Colombia with approximately 100 years of production history, located in the Middle Magdalena Valley Basin. The field production comes from the C zone reservoir of Mugrosa Formation where the depositional environment is a fluvial meandering system. The reservoir has a high heterogeneity and it is defined as an interbedding of sandstones, shales and siltstones with an average thickness of 600 ft and a permeability range from 80 mD to 2 Darcy. The field has been under secondary recovery since the 1960's and in 2005 a redevelopment of the water flooding process began. The field has approximately 400 patterns and 1,000 active producer wells, 95% of which are under a water flooding process. Injector wells have a selective string completion, composed of mandrels and packers, independently injecting in different sand units. Currently, there are patterns with low areal efficiency and consequently lower than expected recovery factor. An interwell tracer project was executed in a six pattern pilot sector, composed of 16 distinct mandrels, in order to validate the need of a conformance treatment to improve current conditions and have a better understanding of the reservoir connectivities. In each selected mandrel a unique tracer family was used in order to accurately intepret breakthough results.
The workflow in the project starts by using the results of the tracer test to estimate swept volume and flow geometry in all patterns. The swept zone represents the thief zone in each pattern and provides an insight of how poor the areal efficiency of the pattern is. Flow geometry is represented in an F- Φ curve and the tangent is related to the residence time of an arbitrary flow line, which is used to first recognize the need for a conformance job and then to calculate the fraction of the swept volume needed to treat. The last step of the workflow is to estimate the incremental oil production rates derived from treating the thief zone. Two analytic methods were derived for the incremental oil production rate estimates. The conformance candidates were ranked according to treatment volume vs. incremental oil recovered over a two-year timeframe. Those results are in process of being analyzed.
The results of the inter-well tracer showed that conformance is needed in 6 individual mandrels and there is a strong relationship between the facies architecture and the flow distribution of the injected water. Also, it will improve the definition of the job portfolio for the conformance project which considers 80 candidates and 2.7 MMBO resources.
The application of conformance treatments is a novelty in multilayer mature oil fields under water flooding process in Colombia, and the study of inter well tracers is essential for the success of this IOR technology.
Holubnyak, Yevhen (Kansas Geological Survey) | Watney, Willard (Kansas Geological Survey) | Hollenbach, Jennifer (Kansas Geological Survey) | Rush, Jason (Kansas Geological Survey) | Fazelalavi, Mina (Kansas Geological Survey) | Bidgoli, Tandis (Kansas Geological Survey) | Wreath, Dana (Berexco LLC)
Baseline geologic characterization, geologic model development, studies of oil composition and properties, miscibility pressure estimations, geochemical characterization, reservoir modelling were performed. In March of 2015 the injection well (class II) KGS 2-32 was drilled, cored, and logged through an entire anticipated injection interval. Whole core samples were obtained and tested for porosity and permeability, relative permeability, and capillary pressure. The Drill Stem Test (DST) was also conducted to estimate injection interval permeability and pore-pressure. After the injection well KGS 2-32 was acidized, Step Rate (SRT) and Interference (IT) tests were conducted and analysed for permeability, well pattern communication, and fracture closing pressure.
Approximately 20,000 metric tons of CO2 was injected in the upper part of the Mississippian reservoir to verify CO2 EOR viability in carbonate reservoirs and evaluate a potential of transitioning to geologic CO2 storage through EOR. Total of 1,101 truckloads, 19,803 metric tons, average of 120 tonnes per day were delivered over the course of injection that lasted from January 9 to June 21, 2016. After cessation of CO2 injection, KGS 2-32 well was converted to water injector and is currently continues to operate. CO2 EOR progression in the field was monitored weekly with fluid level, temperature, and production recording, and formation fluid composition sampling.
As a result of CO2 injection observed incremental average oil production increase is ~68% with only ~18% of injected CO2 produced back. Simple but robust monitoring technologies proved to be very efficient in detection and locating of CO2. High CO2 reservoir retentions with low yields within actively producing field could help to estimate real-world risks of CO2 geological storage.
Wellington filed CO2 EOR was executed in a controlled environment with high efficiency. This case study proves that CO2 EOR could be successfully applied in Kansas carbonate reservoirs if CO2 sources and associated infrastructure is available.
Barnes, J. R. (Shell Global Solutions International B.V.) | Regalado, D. Perez (Shell Global Solutions International B.V.) | Crom, L. A. (Shell Global Solutions U.S. Inc.) | Doll, M. J. (Shell Global Solutions U.S. Inc.) | King, T. E. (Shell Global Solutions U.S. Inc.) | Covin, D. Y. (Shell Chemical Company L.P.) | Crawford, J. N. (Shell Chemical Company L.P.) | Kunkeler, P. J. (Shell Chemicals Europe B.V.)
Surfactant quantities increase dramatically moving from small field tests (e.g. single well tests) to multiwell pilots to full scale EOR projects. This paper is a companion paper to SPE-190453, presented at the SPE conference in Oman in March 2018, and shows how best practices from existing large-scale surfactant manufacture (for household and industrial applications) can be applied and adapted for manufacture and delivery of EOR surfactants as field projects are upscaled.
Surfactant concentrates can be viscous, making them difficult to pump and mix. This paper presents improved methods to manufacture and handle them. In addition, dilution of the concentrate in the field to the working (injected) formulation needs to be carried done in a manner which avoids the formation of viscous phases that are common with surfactants.
The main learnings from this paper are: For small field projects, it is usually advantageous to ship less concentrated products (e.g. ≤ 30% active matter, AM) as, for the small volumes involved, the advantages of ease of mixing and dilution in the field tend to outweigh the cost savings in transporting a highly concentrated product. An additive (viscosity modifier), applied during manufacture, reduces viscosity and improves handleability of highly concentrated products (e.g. ≥ 65% AM). This viscosity modifier is benign for sub-surface performance of the surfactant. For large projects, two strategies can be used to reduce logistics costs: Supply a concentrated product with viscosity modifier (to reduce the percentage of water shipped), and/or Manufacture the product (or part of the product) in country/region and near the field. A realistic supply chain was used to estimate the logistics costs to transport low and high %AM products from a USA point of manufacture to an EOR project destination in South America. This calculation assumed an equal manufacturing cost for the low and high %AM products and transportation by 20 ton ISO-tanks, a standard bulk industry container. The transportation cost for the high %AM product is around 57% of the low %AM product. Additional logistics savings are achievable through manufacturing the product (or part of the product) in country/region, and the logistics cost for high %AM product manufactured near the field can be reduced to 33% of of that for the low %AM product manufactured in the USA.
For small field projects, it is usually advantageous to ship less concentrated products (e.g. ≤ 30% active matter, AM) as, for the small volumes involved, the advantages of ease of mixing and dilution in the field tend to outweigh the cost savings in transporting a highly concentrated product.
An additive (viscosity modifier), applied during manufacture, reduces viscosity and improves handleability of highly concentrated products (e.g. ≥ 65% AM). This viscosity modifier is benign for sub-surface performance of the surfactant.
For large projects, two strategies can be used to reduce logistics costs: Supply a concentrated product with viscosity modifier (to reduce the percentage of water shipped), and/or Manufacture the product (or part of the product) in country/region and near the field.
Supply a concentrated product with viscosity modifier (to reduce the percentage of water shipped), and/or
Manufacture the product (or part of the product) in country/region and near the field.
A realistic supply chain was used to estimate the logistics costs to transport low and high %AM products from a USA point of manufacture to an EOR project destination in South America. This calculation assumed an equal manufacturing cost for the low and high %AM products and transportation by 20 ton ISO-tanks, a standard bulk industry container. The transportation cost for the high %AM product is around 57% of the low %AM product. Additional logistics savings are achievable through manufacturing the product (or part of the product) in country/region, and the logistics cost for high %AM product manufactured near the field can be reduced to 33% of of that for the low %AM product manufactured in the USA.
More general learning for EOR projects are: Experience from the wider, bulk chemicals industry can be usefully applied for EOR projects. It is important to align surfactant manufacture/supply logistics with reservoir management and the field life plan as significant lead time is required for supply of large surfactant volumes.
Experience from the wider, bulk chemicals industry can be usefully applied for EOR projects.
It is important to align surfactant manufacture/supply logistics with reservoir management and the field life plan as significant lead time is required for supply of large surfactant volumes.
Føyen, T. L. (Dept. of Physics and Technology, University of Bergen) | Fernø, M. A. (Dept. of Physics and Technology, University of Bergen) | Brattekås, B. (The National IOR Centre of Norway, Dept. of Energy Resources, University of Stavanger)
Spontaneous imbibition is a capillary dominated displacement process where a non-wetting fluid is displaced from a porous medium by the inflow of a more-wetting fluid. Spontaneous imbibition strongly impacts waterflood oil recovery in fractured reservoirs and is therefore widely studied, often using core scale experiments for predictions. Decades of core scale experiments have concluded that spontaneous imbibition occurs by a uniformly shaped saturation front and that the rate of imbibition scales with square root of time. We use emerging imaging techniques to study local flow patterns and present new experimental results where spontaneous imbibition deviates from this behavior.
The imbibition rate during early stages of spontaneous imbibition (the
Wang, Haitao (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development) | Lun, Zengmin (Petroleum Exploration & Production Research Institute, SINOPEC) | Lv, Chengyuan (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development) | Lang, Dongjiang (Petroleum Exploration & Production Research Institute, SINOPEC) | Luo, Ming (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development) | Zhao, Qingmin (Petroleum Exploration & Production Research Institute, SINOPEC) | Zhao, Chunpeng (State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development)
The reservoirs in Qian 34 10 rhythmic layer of Qianjiang Basin were shale oil with intersalt sediments. During natural depletion development process production rapidly decreased. Water injection and CO2 injection were considered as potential technology for shale oil EOR. Due to high salt content of shale rock and dissolution of salt in water, water injection damaged the reservoirs. CO2 injection didn't react with salt to damage the reservoirs. Meanwhile, CO2 could enter micro pores of reservoir rock and mobilize oil by the mechanisms of diffusion, extraction and swelling and so on. In order to verify oil mobilization in shale exposed to CO2 exposure experiments based on nuclear magnetic resonance (NMR) were conducted in this study.
NMR T2 spectrum can measure the oil signal and determine the oil content of rock with low permeability. In this study 10 fresh shale samples (from 6 depths) were measured and oil contents were determined using NMR T2 spectrum. Two shales with higher oil content were selected and performed exposure experiment. Under the temperature of 40 °C and the pressure of 17.5 MPa fresh shale was exposed to CO2 and NMR T2 spectrum was used to measure the oil content of shale continuously. Oil mobilization in shale exposed to CO2 was determined.
The results of NMR T2 spectrum showed that NMR signals of 9 fresh shale samples were good and oil contents of fresh shales were high. Recovery of S5# shale exposed to CO2 was 51.2% after 8 days. Recovery of S9# shale exposed to CO2 was 55.8% after 6.1 days. These results indicated that more than half of shale oil were mobilized with relative long exposed time during CO2 injection. The results of NMR T2 spectrum showed that oil in all pores could be mobilized as exposure time increased.
This study showed the quantitative results for CO2 injection and EOR in shale oil of Qianjiang Basin. All conclusions provided confidence to start CO2 EOR pilot project in shale oil with intersalt sediments with ultra-low permeability.
Aamodt, G. (ConocoPhillips Skandinavia AS) | Abbas, S. (ConocoPhillips Co) | Arghir, D. V. (ConocoPhillips Skandinavia AS) | Frazer, L. C. (ConocoPhillips Co) | Mueller, D. T. (ConocoPhillips Co) | Pettersen, P. (ConocoPhillips Skandinavia AS) | Prosvirnov, M. (ConocoPhillips Skandinavia AS) | Smith, D. D. (ConocoPhillips Co) | Jespersen, T. (Halliburton Co.) | Mebratu, A. A. (Halliburton Co.)
This paper discusses a field case review of the processes used to identify, characterize, design and execute a solution for a waterflood conformance problem in the Ekofisk Field that developed in late 2012. The Ekofisk Field is a highly-fractured Maastrichtian chalk reservoir located in the Norwegian sector of the North Sea. Large scale water injection in the field began in 1987 and overall the field has responded well to waterflood operations. However, fault reactivation coupled with extensive natural fractures and rock dissolution has resulted in some challenging conformance issues. In late 2014, a solution was executed to control this problem. Details of the diagnostic efforts and how this data was used to identify, characterize and mitigate an injector/producer connection through a void space conduit (VSC) will be outlined and discussed. These diagnostics include pressure transient analysis (PTA), interwell tracers, injection profiles, seismic mapping, fluid rate analysis, fluid composition and temperature monitoring. The importance of this data analysis is the key element necessary to select an effective solution.
The selected approach involved pumping a large tapered nitrified cement treatment into the offending injector, which is believed to be the single largest nitrified cement operation ever pumped within the oil industry. Because of extremely rapid communication with an offset producer, a protective gel was used to reduce the risk of cement entry into that producer. A brief review of alternative mitigation options and the reasons for selecting the nitrified cement treatment will be discussed. Additionally, a complete review of the shutoff technique, product, damage mitigation strategy, and complications associated with timing and coordination in an offshore environment will also be discussed. Finally, a summary of lessons learned, job execution observations, post-treatment performance results over the past three years, and forward plans will be presented. Based on these results it is believed that there are a number of opportunities to add strong value through conformance engineering.
For waterflooding in argillaceous reservoirs, the injection water needs to be carefully designed to avoid formation damage by clay swelling and migration. Common methods of achieving this are compatibility tests of injection water with formation water and rocks and injectivity tests. However, such tests are often not practical nor even possible due to the limited availability and prohibitive cost of obtaining actual reservoir cores. The objective of this work was to develop a cost-effective method to evaluate injectivity that does not require the use of reservoir core. In this study, a novel coreless injectivity method was developed and validated. The method utilizes field-produced drill cuttings to make synthetic core plugs, which are universally available during well drilling and commonly considered as waste. A specially designed cleaning process was performed for the drill cuttings. They were then wet compressed with a high-pressure hydraulic press and dried in a constant-humidity oven to make core plugs with standard dimensions. Drill cutting plugs prepared in this way can then be used for injectivity tests as an alternative to actual reservoir core plugs. The routine core analysis revealed that, although sedimentary structures were lost, the drill cutting plugs preserved the mineralogy and maintained comparable porosity and permeability to the reservoir plugs. To validate the representativeness of the formation damage tendencies of the drill cutting plugs, water injectivity tests were carried out on both preserved reservoir cores and compressed drill cutting cores, using simulated injection water with successively lower salinities. The results showed that injectivity loss as indicated by increasing pressure drop was consistent with both types of cores. The "coreless injectivity evaluation" technique can be applied for argillaceous reservoirs with formation damage concerns. It is a cost-effective and viable technique for evaluating water injectivity when reservoir cores are unavailable.
Al-Rushaid, Mona (Kuwait Oil Company) | Al-Rashidi, Hamad (Kuwait Oil Company) | Ahmad, Munir (Kuwait Oil Company) | Azari, Mehdi (Halliburton) | Hadibeik, Hamid (Halliburton) | Kalawina, Mahmoud (Halliburton) | Hashmi, Gibran (Halliburton) | Hamza, Farrukh (Halliburton) | Ramakrishna, Sandeep (Halliburton)
Reservoir relative permeability and capillary pressure, as a function of saturation, is important for assessing reservoir hydrocarbon recovery, selecting the well completion method, and determining the production strategy because they are fundamental inputs to reservoir simulation for predicting lifetime production of a well. Estimation of relative permeability and capillary pressure curves at reservoir conditions is also an important task for successful planning of waterflooding and enhanced oil recovery. The relative permeability and capillary pressure data estimated from core analysis might cause concern regarding representativeness, and adjustments are typically necessary for successful production forecasting. This paper proposes a new method to obtain relative permeability and capillary pressure curves with downhole pressure-transient analysis (PTA) of mini-drillstem tests (miniDSTs) and well log-derived saturations.
The new approach was based on performing miniDSTs in the free water, oil, and oil-water transition zones. Analyses of the miniDST buildup tests provided absolute formation permeability, endpoints of relative permeability to both oil and water, and curvature of the relative permeability data. Additionally, resistivity, dielectric, and nuclear magnetic resonance (NMR) logs were used to determine irreducible water, residual oil, and transition zone saturations. Combining these downhole measurements provided the relative permeability and capillary pressure curves.