Miscible Gas Injection EOR Complex Challenges – A CCUS Hub Approach to Unlock Value for a Multi Reservoir Onshore Field

Miscible CO2 flood is a well-established proven EOR recovery mechanism. There have been a large number of CO2 EOR developments worldwide, in both carbonate and clastic reservoirs. Potential control or influence factors on incremental production and incremental recovery over water flood are well documented in the published literature. Some of the published CO2 EOR developments have reported relatively high incremental recoveries. ADNOC is a leader in miscible gas injection EOR in carbonate reservoirs. There are a number of ongoing miscible gas injection EOR developments within its portfolio contributing a significant amount of production. Miscible CO2 flood is a key EOR development for ADNOC. Following intensive screening studies and laboratory experiments, the first CO2 EOR pilot in the MENA region was conducted as early as 2009 in one of ADNOC Onshore fields. This paved the way for further large-scale deployment and CO2 WAG pilots starting in 2016, both onshore. Appreciable progresses have been made since 2009. This bodes well with the significant initiatives undertaken by the UAE towards carbon emissions and greenhouse gas reduction, climate control and sustainable development. There are broad consensus that climate changes are now and will continue to affect all countries on all continents. Potential global warming can disrupt national economies and adversely impact on lives, costing people, communities and countries already today and perhaps more in the future. Carbon Capture, Utilization, and Storage (CCUS) technologies have been making headlines and attracting increasing amount of renewed attention, because they are in line with meeting global greenhouse gas reduction goals, and contributing towards climate control and sustainable development. The giant Abu Dhabi onshore field consists of 6 carbonate reservoirs. Several pilots, immiscible hydrocarbon gas injection and CO2 WAG, and a pattern immiscible gas injection WAG flood have been executed. Miscible gas injection EOR is therefore field proven. However, due to large field size, surface congestion constraints, geological and fluid variations, miscible gas injection EOR development by reservoir individually becomes complex and economically challenging. This paper presents a comprehensive study and recommends an integrated CCUS Hub development approach - enabling field-wide EOR development with several hundred million-barrels of incremental recovery. The study follows a step-by-step systematic method. Existing water flood performances were assessed first. History matched full field simulation then leads to identification of CO2 EOR targets by area/flank for each reservoir. These are referred to as sweet development areas. Available advanced PVT data were analysed and a multi-reservoir single equation of state developed. It has been found that only CO2 is miscible across all six reservoirs, while hydrocarbon gas is also miscible for the deepest two reservoirs. Dedicated fine scale sector models (EOR history matched where applicable) were developed to generate multiple CO2 EOR development scenarios, for example, depending on water flood maturity at the time of CO2 EOR start-up, and potential impact on incremental oil production, incremental oil recovery due to reservoir heterogeneity. First results from sector modelling show that quite a few areas/flanks would be sub-economical if CO2 EOR development on a stand-alone basis. Hence the concept of a CCUS Hub is proposed, which would allow sweet development areas in any or all of the six reservoirs to be developed from a single common surface Cluster. There is potential space for development phasing, allowing additional CO2 EOR developments within the same cluster area once ullage and CO2 supply becomes available. The CCUS Hub development approach facilitates optimization and sharing of injection/production flow-lines; surface space, gathering and processing facilities, CO2 supply, CO2 recovery unit deployment coupled with produced gas re-injection into the 2 deepest reservoirs. Compared to a more conventional development approach of reservoir by reservoir, considerable scope for CAPEX and OPEX savings was found. Assuming a constant future oil price, a reduction in development costs would allow more sweet development areas to pass the threshold of economical development, leading to an increase in overall incremental production and recovery from CO2 EOR.

A Geoengineering Approach to Maximum Reservoir Contact Wells Design: Case Study in a Carbonate Reservoir Under Water and Miscible Gas Injection

Maximum Reservoir Contact wells (MRCs) are a potential alternative to reduce the number of wells required to develop hydrocarbon reservoirs, improve sweeping efficiency and delay gas and water breakthrough. The well completions design is critical for the success of MRCs. In this study we present a case study of a MRC well completion design using Limited Entry Liners (LEL) in a mature carbonate reservoir under water and miscible gas injection. We developed an integrated workflow that considered a high-resolution numerical simulation model calibrated to static and dynamic data and wellbore-reservoir models coupling, for capturing the details of the flow interaction between both systems. Flow restrictions in the form of additional pressure drops to the flow from the reservoir into the wellbore were used to simulate the effect of small open flow areas, i.e.shot densities, in the LELs. Our work allowed identifying the most likely entry points of gas and water and design the well to minimize their impact on oil production. We observe that longer lengths open to flow outweighs the detrimental effect of producing from intervals closer to the water saturated zones. We also observed that balancing the inflow profile along the wellbore did not report beneficial results to oil production as it stimulates production from the reservoir zone from which the gas breakthrough is expected (middle of the producing section); this result is particularly relevant as it shows that designing the well completions with base only on static data could lead to poor production performance. The suggested completion for the MRC well encompasses four segments; a segment covering almost 50 % of the well length and located at the middle of the producing section with a blind liner (close to flow for gas control) and the remaining three with slotted liners with enough open area as to avoid causing significant pressure drops.

Miscible WAG Efficiency Assessment on a Large Mature Carbonate Field

This paper is based on the analysis of miscible WAG for an onshore Middle-East field, with strongly undersaturated light oil. Water Alternate Gas operations have been ongoing for around 5 years, which is relatively recent compared to more than 40 years of production history. Goal of this work was to assess the efficiency of this miscible hydrocarbon WAG and to optimize it on the different compartments, with respect to miscibility, voidage replacement, and recycling. As this is a large mature field, with WAG operations dispatched on around 50 injectors and 9 fault blocks (compartments), the method of analysis had to be robust with respect to the different injection strategies followed in the past. It was essentially based on injection and production data, but also used pressure data when available. We computed the following dimensionless variables: oil recovery factor, BSW, voidage replacement ratio (VRR), and also WAG ratio and gas recycling ratio (GRR). Their evolution versus time was analyzed and compared between fault blocks. Using dimensionless variables allowed to compare fault blocks with different initial volumes in place, and to illustrate trends versus time. It was also found beneficial to lump some compartments, when communication was substantiated by pressure data. On the production side, we used the conventional BSW and GOR variables to quantify the water and gas recycling ratio. On the injection side, we observed that in some compartments, the historical WAG ratio was too low in the oil zone, which could be quantified by excluding the peripheral water injection volumes. The analysis allowed also to estimate the gas utilization factor and efficiency, which confirmed the overall high efficiency of miscible gas injection in 3-phase mode. It was also found that the injected fluid efficiency correlated with geology: gas injection tends to be more efficient in zones with high permeabilities at the bottom (coarsening downwards), while water injection is better adapted to zones with high permeabilities at the top (coarsening upwards). Estimating these water and gas efficiencies also allowed to optimize the injection strategy on a field level, by comparing the water efficiency with other units of the field only under waterflood.

Successful Implementation of Low-Pressure Operations LPO Projects: Delivering Low UTC Incremental Oil in Low Oil Price Market

Southern Oman has several high pressure (500-1000 bar), deep (3-5 km) and critically sour oil fields (H2S/CO2 up to ~10%/25%). Most of these reservoirs are carbonate stringers encapsulated in salt lacking any natural aquifer support. Field Development strategy for most of the reservoirs in the cluster is primary depletion followed by miscible gas injection. No artificial lift mechanism is installed in these fields, as gas flood is expected to provide the necessary energy later. Many of these fields are depleted and reached lift-die out conditions due to high backpressure from the station. To extend the depletion production life, the team came with Low-Pressure Operation (LPO) project for these fields. This concept was successfully implemented in various fields across the 3 production stations in the cluster. LPO concept is a novel, pragmatic and cost-effective solution to continue production from previous lift die-out wells which is first of its kind in the company. This approach helped to utilize the existing infrastructure and ullage available in the facilities and eliminate the need for installing expensive and complex artificial lifts (e.g. ESP) or depletion compressor systems. This resulted in incremental production at very low UTC and low CAPEX requirements during the low oil price period.

Technological Features of Associated Petroleum Gas Miscible Injection MGI in Order to Increase Oil Recovery at a Remote Group of Fields in Western Siberia

The problem of associated petroleum gas utilization is especially urgent for fields located far from infrastructure facilities for raw gas transportation and treatment. For such fields, alternative methods of gas utilization, especially gas re-injection, are becoming relevant. The re-injection options include: injection into underground reservoir for storage (if there are reservoirs suitable for injection near the field), injection into a gas cap, if any, or injection into a productive reservoir. The latter method allows, along with solving the problem of gas disposal, to increase oil recovery. This study describes an example of miscible gas injection into the reservoir at the Chatylkinskoye field, the infrastructure assumptions which make this option a better one versus a selling option, and the features of a gas treatment and injection process.

Minimum Miscibility Pressure of Gas Injection in Unconventional Reservoirs

Unconvnetional reservoirs are predominantly consisted of nanoscale pores. The strong confinement effect within nanopores imposes significant deviations to the confined fluid phase behavior. Minimum miscibility pressure (MMP) in unconventional reservoirs, as a parameter highly related to the phase behavior of confined fluids, is inevitably affected by the nanoscale confinement. The objective of this work is to investigate the impact of nanoscale confinement on MMP of unconventional reservoir fluids and to recognize a reliable theoretical approach to determine the MMP values in unconventional reservoirs. A modified Peng-Robinson equation of state (PR EOS) applicable for confined fluid characterization is applied to perform the EOS simulation of the vanishing interfacial tension (VIT) experiments. The MMP of a binary mixture at bulk and 50 nm are obtained via the VIT simulation. Meanwhile, the multiple mixing cell (MMC) algorithm coupled with the modified PR EOS is applied to compute the MMP for the same binary system. Comparison of the calculated results to the experimental values recognize that the MMC approach has higher accuracy in determining the MMP of confined fluid systems. Moreover, this approach is then applied to predict the MMP values of both Bakken and Eagle Ford oil at different pore sizes with various injected gases. Results demonstrate that the nanoscale confinement causes drastic suppression to the MMP of unconventional reservoir fluids and the suppression rate increases with decreasing pore size. The drastic suppression of MMP is highly favorable for the miscible gas injection EOR in unconventional reservoirs.

Minimum Miscibility Pressure of CO2/Hydrocarbon Systems Within Nanopores

Minimum miscibility pressure (MMP), as a key parameter for the miscible gas injection enhanced oil recovery (EOR) in unconventional reservoirs, is affected by the dominance of nanoscale pores. The objective of this work is to investigate the impact of nanoscale confinement on MMP of CO2/hydrocarbon systems and to compare the accuracy of different theoretical approaches in calculating MMP of confined fluid systems. A modified PR EOS applicable for confined fluid characterization is applied to perform the EOS simulation of the vanishing interfacial tension (VIT) experiments. The MMP of multiple CO2/hydrocarbon systems at different pore sizes are obtained via the VIT simulations. Meanwhile, the multiple mixing cell (MMC) algorithm coupled with the same modified PR EOS is applied to compute the MMP for the same fluid systems. Comparison of these results to the experimental values recognize that the MMC approach has higher accuracy in determining the MMP of confined fluid systems. Moreover, nanoscale confinement results in the drastic suppression of MMP and the suppression rate increases with decreasing pore size. The drastic suppression of MMP is highly favorable for the miscible gas injection EOR in unconventional reservoirs.

A New Predictive Method for CO2-Oil Minimum Miscibility Pressure

Gas injection processes are among the effective methods for enhanced oil recovery. Miscible and/or near miscible gas injection processes are among the most widely used enhanced oil recovery techniques. The successful design and implementation of a miscible gas injection project are dependent upon the accurate determination of minimum miscibility pressure (MMP), the pressure above which the displacement process becomes multiple-contact miscible. This paper presents a method to get the characteristic curve of multiple-contact. The curve can illustrate the character in the miscible and/or near miscible gas injection processes. Based on the curve, we suggest a new model to make an accurate prediction for CO2-oil MMP. Unlike the method of characteristic (MOC) theory and the mixing-cell method, which have to find the key tie lines, our method removes the need to locate the key tie lines that in many cases is hard to find a unique set. Moreover, unlike the traditional correlation, our method considers the influence of multiple-contact. The new model combines the multiple-contact process with the main factors (reservoir temperature, oil composition) affecting CO2-oil MMP. This makes it is more practical than the MOC and mixing-cell method, and more accurate than traditional correlation. The method proposed in this paper is used to predict CO2-oil MMP of 5 samples of crude oil in China. The samples come from different oil fields, and the injected gas is pure CO2. The prediction results show that, compared with the slim-tube experiment method, the prediction error of this method for CO2-oil MMP is within 2%.