Study on the influence of the viscosity reducer solution on percolation capacity of thin oil in ultra-low permeability reservoir

One of the practical limitations of cold heavy oil production method in unconsolidated reservoirs is sand production that leads to very low recovery factor (5-15%). To target the remaining 85-95% heavy oil resources, several enhanced oil recovery (EOR) techniques such as cyclic solvent injection (CSI) have been proposed. Due to its potential success in Canada and elsewhere, this paper reviews the technical and efficiency requirements of CSI EOR in heavy oil reservoirs. To have an improved understanding of the conditions that result in a successful CSI process, we reviewed the dominant driving mechanisms of CSI at reservoir conditions such as fluid displacement, pressure gradients, non-equilibrium gas dissolution/exsolution, potential formation collapse, and deformation issues; the interest is on the application of CO2 as a solvent. Limitations of current thermal and non-thermal EOR methods were briefly compared against the CSI in thin oil reservoirs. To complete the assessment, several case studies and lessons learned from CSI applications were included based on the latest laboratory experiments, numerical studies, in addition to the CSI pilot/field tests. Specific to thin heavy oil reservoirs with sand production (e.g. CHOPS), incremental oil recovery requires to re-energize the depleted reservoirs in a cyclic manner, aiming to provide more drive energy by economical gaseous solvents (e.g. CO2). It was realized that other EOR techniques such as waterflooding, gas flooding, and steam injection can face major issues with flow and heat efficiencies, including fingering and significant heat/solvent losses; this makes CSI a feasible EOR alternative. Regarding the solvent use, laboratory experiences have not been conclusive about what solvent stream could result in an improved oil recovery; however, most of the solvents should be designed to either reduce heavy oil viscosity, or strengthen the nucleation and stability of the injected solvent bubbles in the heavy oil reservoir (i.e. foamy oil behavior). To this end, successful field scale CO2 EOR applications have been reported in several oil reservoirs. Although progress has been made, but numerical modelling still faces challenges to properly model the main CSI driving mechanisms, including fluid-solvent interactions and deformation of subsurface reservoirs. Moreover, field implementation indicates that highly productive wells during primary production from unconsolidated reservoirs might also outperform during a follow up CSI process. This work addresses the recent improvements in application of CSI EOR to develop heavy oil reservoirs, especially for thin and poorly consolidated sandstones. The findings of this paper, including the limitations and requirements of different recovery techniques, enable more effective design of field scale CO2 EOR operation in depleted heavy oil reservoirs.

One of the limitations of Cold Heavy Oil Production with Sand (CHOPS) is the low recovery factor (5–15%). To target the remaining 85–95% heavy oil resources, several enhanced oil recovery (EOR) techniques, such as cyclic solvent injection (CSI), have been proposed. Due to its potential success in Canada and elsewhere, this paper reviews the technical and efficiency requirements of CSI EOR in post-CHOPS heavy oil reservoirs. We explain the dominant driving mechanisms of CSI with a focus on the application of CO2 as a solvent. Limitations of current thermal and non-thermal EOR methods were compared to the CSI in thin oil reservoirs. To complete the assessment, several case studies and lessons learned were included based on the latest laboratory experiments, numerical studies, and CSI pilot/field tests. Specific to thin and shallow heavy oil reservoirs with sand production (e.g., CHOPS), the key to recover incremental oil was found to re-energize depleted reservoirs in a cyclic manner with unexpensive solvents (e.g., CO2). Regarding the solvent use, laboratory experiences have not been conclusive about what solvent stream could improve oil recovery. To this end, successful field scale CO2 EOR applications have been reported in several post-CHOPS reservoirs indicating that highly productive wells during primary production might also outperform during a follow up CSI process. Numerical modeling still faces challenges to properly model the main CSI driving mechanisms, including fluid–solvent interaction and the deformation of subsurface reservoirs.

Maximising oil recovery in thin and ultra-thin (<30ft) oil columns is a challenge as a result of conning or cresting of unwanted fluids into the wellbore in both vertical and horizontal wells. There is considerable oil left behind, above the well completion in the reservoir. This may also occur in horizontal well when bottom or edge water encroachment or invasion takes place. The development of the gas resources from these reservoirs is a major challenge as regulators want optimal development plan for the oil rim before project approval is made. This can delay upstream gas supply to LNG projects and grind down project value. A smart development strategy has been proposed for the development of these challenging reservoirs. This involves the use of intelligent multilateral well in simultaneous oil and gas development; the first (top) horizontal lateral well legs of the multilateral well will be completed at the crest of the reservoir in the gas cap. The second or lower horizontal lateral well leg will be completed, right above the gas-oil contact. Extensive numerical reservoir flow simulation has been used to demonstrate the ability and possibility of using a single wellbore for simultaneous oil and gas production. This proposed development strategy will provide high impact on the asset of such oil and gas reservoir by providing a cost effective technology solution. The numerical simulation results show that the intelligent multilateral well will significantly improve the overall cumulative production of gas and oil from a thin oil reservoir with large gas cap as compared to conventional wells and also provide opportunity for auto gas lift for low API gravity crude. This paper presents; i) the use of intelligent multilateral wells to simultaneously produce oil and gas from the same wellbore in the thin oil reservoir and ii) provide information on the delay and reduction of excess production of unwanted fluids (water) during oil and gas production from thin oil reservoir using intelligent well technology including cost effectiveness.

Summary Maximizing oil recovery in thin and ultrathin (less than 30 ft) oil columns is a challenge as a result of coning or cresting of unwanted fluids into the wellbore in both vertical and horizontal wells. There is considerable oil left behind, above the well completion in the reservoir. This may also occur in horizontal wells when bottom- or edgewater encroachment or invasion takes place. The development of the gas resources from these reservoirs is a major challenge because regulators want an optimal development plan for the oil rim before project approval is made. This can delay upstream gas supply to liquefied-natural-gas (LNG) projects and grind down project value. A smart development strategy has been proposed for the development of these challenging reservoirs. This involves the use of intelligent multilateral wells in simultaneous oil and gas development; the first (top) horizontal-lateral-well legs of the multilateral well will be completed at the crest of the reservoir in the gas cap. The second (lower) horizontal-lateral-well leg will be completed just above the gas/oil contact (GOC). Extensive numerical reservoir-flow simulation has been used to demonstrate the ability and possibility of using a single wellbore for simultaneous oil and gas production. This proposed development strategy will provide high impact on the asset of such oil and gas reservoirs by providing a cost-effective-technology solution. The numerical-simulation results show that the intelligent multilateral well will significantly improve the overall cumulative production of gas and oil from a thin oil reservoir with a large gas cap compared with conventional wells and also provide the opportunity for automatic gas lift for low-gravity crude (°API). This paper (1) presents the use of intelligent multilateral wells to produce oil and gas from the same wellbore simultaneously in the thin oil reservoir and (2) provides information on the delay and reduction of excess production of unwanted fluids (water) during oil and gas production from thin oil reservoirs using intelligentwell technology, including cost effectiveness.

Reservoirs of high viscosity and low permeability are abundant and widely distributed in various countries, which can contribute an important percentage of oil output in the world. Conventional chemical flooding are suitable for low viscosity oil (less than 30 mPa·s) and medium/high permeability reservoirs (more than 50mD). However, it is a great challenge to applied chemical flooding technology for higher viscosity (30-500mPa·s) oil and lower permeability (1-50mD) reservoirs. On the one hand, the high contents of resin and asphaltene, or the formation of wax crystals in low reservoir temperature, lead to high oil viscosity and low oil recovery; On the other hand, low permeability can cause injection difficulty, and conventional chemical agents (polymers and formulations of chemical combination flooding) are difficult to inject. At present, the main exploitation mode is water flooding. However, because of high oil viscosity and low oil fluidity, the water flooding recovery is only about 15%. So it is very necessary to develop effective development technology. It is a good choice to develop water flooding with the intelligent viscosity reducer to decrease oil viscosity and improve oil fluidity, which has small molecular weight and can inject low permeability reservoirs easily. The performances of the viscosity reducer were studied in detail, including viscosity reduction efficiency, tripping oil film capacity, interfacial property, oil-displacement efficiency etc. The novel viscosity reducer with intellectual property show excellent properties. The viscosity reduction efficiency of the viscosity reducer was more than 80% (from 64.4 mPa·s to 10.3 mPa·s), and it could strip oil film within 40 seconds quickly, and could achieve ultra-low Interfacial Tension (IFT, less than 1.0×10-2mN/m).Alkali (NaOH or Na2CO3) could help to increase the viscosity reducing effects, and improve the stripping oil film capacity and interfacial property.The viscosity reducer had high oil-displacement efficiency; after water flooding, Oil recoveries increased 23% (OOIP, Original Oil In Place) with thehelp of this viscosity reducer.The novel viscosity reducer has viscoelasticity and shear-thinning ability. The monomer molecules can form the three-dimensional network structure in aqueous solution with high viscosity, which plays a role in enlarging the swept volume. With the increase of the shear rate, the three-dimensional network structure is broken down into the monomer molecules, and the viscosity decreases rapidly, so the viscosity reducer solution can inject low permeability reservoir easily.Compared with conventional polymer and polymer-surfactant, this viscosity reducer solution had better shear resistance and injectivity, and could filter membrane (0.2μm pore) effectively. The novel viscosity reducer can substitute for conventional polymer and polymer-surfactant in chemical flooding. This paper provides insights of a new effective EOR way for high viscosity and low permeability reservoirs.

The work discusses the unique challenge of developing deep and thin oil reservoirs spread across onshore and offshore area of Abu Dhabi. The field is being developed with a cluster development approach utilizing available Natural/artificial Islands in offshore areas. The reservoirs under considerations are thin heterogeneous carbonate reservoirs with moderate permeability (avg ~<10-15 mD) and containing volatile to critical oil. The reservoirs were discovered quite early; limited data is gathered in old wells and have associated uncertainties. Some wells were deepened for sake of collecting additional data; very few completed lately under early production scheme (EPS) to evaluate the well potential, performance sustainability, reservoir drive etc. Their production behaviors also carry an overprint of reservoir diagenesis. The available data, their associated uncertainty and EPS performance are combined to build a holistic reservoir understanding and field development plan, under implementation with phased drilling. An early water-alternate-gas injection (WAG) is planned to support declining reservoir pressure in volatile oil reservoirs in absence of aquifer support. These reservoirs comprise of thin parasequences (<10 ft) separated by dense intervals associated with stylolites; reservoir thickness falling below seismic separation limit. The structural setting is complex due to undulating anticlines and extensive faulting. Diagenesis has heavily influenced reservoir properties, making significant reservoir saturation profile variation both laterally and vertically. This has been confirmed with production performance of EPS wells, behaving differently due to their areal location. The current development plan considers producers with 4000’ horizontal lateral in high oil saturation along with multiple sub-zone coverage to achieve an effective depletion strategy. The limited data availability, structural uncertainty and reservoir heterogeneity in combination with limitation of cluster drilling rig capacity has made well placement a challenging task. Placement of horizontal laterals in good reservoir properties, away from gas cap or O/W transition zones is achieved by utilizing unified understanding of structure, carbonate lithology, diagenesic imprints, logs, analogue saturation-height function, openhole tests and production data. The learning from each new well is incorporated to optimize further development plan. The reservoir quality of completion interval is critical in terms of saturation considering water production, well lifting and long term sustainability. The learning from successful implementation of WAG in another reservoir of the field is incorporated. Understanding from production behavior during EPS has provided a broad guideline for reservoir development; this paper discusses the challenges of implementation and their mitigation approach.

Horizontal wells have been developing on a large scale in an oil field with low permeability and thin oil layer, and the horizontal wells have entered the high water-cut stage, it is difficult to adjust the horizontal wells by conventional technology. Therefore, it is necessary to apply the numerical simulation results of horizontal wells to improve the development level of horizontal wells. Through the study of horizontal well man-made fracture equivalent simulation and layered and segmented simulation technology, the fine simulation of horizontal wells is realized. Combined with different well pattern types, seepage differences and research results of numerical simulation models, the distribution rule of remaining oil in horizontal wells and the production status of different segments of horizontal wells are summarized. Finally, it is clear that the remaining oil in the horizontal well area of the low permeability and thin oil layer is mainly concentrated in the areas of poor water drive control, interference between vertical wells and horizontal wells, pressure interference, interlayer interference and fracture interference. Based on the analysis of the production status of different segments of horizontal wells, the main adjustment direction in the horizontal well area is thin injection thick production section and thick injection thin production section with strong regional heterogeneity and relatively large connectivity differences. The study on numerical simulation method and remaining oil distribution of horizontal well in low permeability and thin oil reservoir provide the basis for fine potential tapping of horizontal well in the next step.KeywordsLow permeability thin oil reservoirHorizontal wellNumerical simulationRemaining oil

Oil production from thin oil rim reservoirs with strong aquifers and large gas caps is challenging due to early gas and water breakthrough, movement of the fluid contacts and low oil recovery factor. One means of handling the problems associated with thin oil reservoirs is the use of horizontal wells which improves recovery factor. This work however proposes a measure through which gas injection into the reservoir is used to improve oil recovery factor and minimize water production using vertical wells. A simulation study was carried out using the data from a thin oil rim reservoir in the Niger Delta. The five cases studied are the base case (using conventional vertical wells), use of horizontal wells, water production and disposal, water production and re-injection into the oil zone to improve recovery, and gas injection at the oil water contact. The recovery factor and volume of produced water were compared for all five cases for a production period of 40years. An oil recovery factor of 25%, 29%, 40%, 33% and 44% were obtained for the base case, use of horizontal wells, water production and disposal, water production and re-injection to improve recovery, and gas injection at the oil water contact respectively. Volume of produced water was lowest while the GOR was highest for the proposed method than any other method. The main disadvantage using the approach of injecting gas at the water oil contacat is the high GOR however; recycling the gas by injecting the produced gas back into the gas cap is a viable solution. The relatively higher oil recovery factor and minimal volume of produced water which are highly desired for effective production from thin oil reservoirs makes the proposed technique worth investigating.

This paper considers the mechanisms and characteristic flow patterns of low permeability reservoir systems. In this paper we focus on the issue of low permeability in conjunction with reservoir heterogeneity (as these often go hand in hand). Generally speaking, we focus on the single-phase gas flow case as this is most relevant — and we avoid concerns related to multiphase flow. Low permeability reservoir systems exhibit unique flow behavior for the following reasons: Low permeability (which yields poor utilization of reservoir pressure), this is caused in part by: –Depositional issues: very small grains, mixed with detrital muds (clays).–Diagenetic issues: clay precipitation, massive cementation, pressure compaction, etc. Reservoir heterogeneity — dictated by deposition and post-deposition (diagenetic) events, including: –Vertical heterogeneity: layering, laminae, etc.–Lateral heterogeneity: medium to large scale geologic features (e.g., turbidite deposition, faults, etc.).–Differential diagenesis, including hydrocarbon generation and migration. These characteristics lead us to the relatively simple observation that low permeability reservoirs are simply poor conductors offluids. As a matter of background, this work discusses the issues relevant to the origin of low (and ultra-low) permeability reservoirs, but our primary focus is flow at macro- and mega-scales (as would be observed at a well). An obvious comment at this point is that the reservoir permeability and the reservoir heterogeneity are fixed constants that we can not change. While true, we can change our mechanism for accessing the reservoir (i.e., the well) and we can change our development strategy to ensure optimal performance and recovery of a particular reservoir. As for changing our access to the reservoir, we can utilize hydraulic fracture stimulation techniques to create a conductive pathway into the reservoir from the well. This is and will be implicit in the continued development of low and ultra-low permeability reservoirs — regardless of the well type (vertical or horizontal). In this work, our emphasis is to consider the relatively simple case of a single vertical well with a hydraulic fracture and the resulting flow behavior that this type of well will experience. It is our contention that the elliptical flow regime dominates reservoir performance in low/ultra-low permeability reservoirs, and we apply both analytical and numerical solutions to a typical field case to illustrate the validity of the elliptical flow regime.

In order to develop methods to further enhance oil recovery after water flooding in low permeability reservoirs by improving oil displacement efficiency, the displacement mechanism of residual oil was studied by the application of different pertinent measures. For in-depth investigation of oil displacement and variations in residual oil saturation, a large number of visual glass model displacement experiments were performed with different methods, such as changing the displacement direction, cyclic water flooding, displacement pressure difference variation and polymer flooding. In this paper, the models were divided into three (low, medium and high) permeability levels, and the residual oil after water flooding was categorized in five different types: cluster, oil film, oil drop, columnar and blind end residual oil. The experimental results showed that cluster residual oil accounted for the largest proportion after water flooding. In addition, with the increase in model permeability, cluster residual oil saturation increased and other types of residual oil saturations decreased. Compared to other methods, polymer flooding showed maximum displacement efficiency for the same displacement pressure and permeability model. The procedure was then followed by changing the displacement direction, cyclic water flooding and changing the displacement pressure difference. The different residual oil types can be activated by different methods, for example, cluster and columnar residual oil by changing the displacement direction, cluster and columnar residual oil by cyclic water flooding, cluster and oil drop residual oil by increasing displacement pressure difference. Moreover, all of the above mentioned five (05) types of residual oil can be activated by polymer flooding.

To rationally develop low permeability reservoir, enhanced oil recovery, Changqing Oilfield launched a special low permeability oil field development studies. Based Changqing oilfield Yanhewan block this typical ultra-low permeability reservoir, use the numerical simulation method simulate the instability of water injection and gas injection alternating different effects of the development. The simulation results show that injection cycle in the early development of poor results, but the technique ultimately better results in the development of continuous injection; Gas-water cycle alternating six months of the development of better results in alternating cycles of three months, After the first injection of gas injection in better after the first injection of gas injection development effect, the study of the block for the rational development of a new approach.

Carbonate reservoirs are highly heterogeneous and poor in interwell connectivity. Therefore, it is difficult to predict the thin oil layers and water layers inside the carbonate reservoir with thickness less than 10 ft by seismic data. Based on the petrophysical analysis with core and well logging data, the carbonate target layers can be divided into two first level lithofacies (reservoir and non-reservoir) and three second-level lithofacies (oil, water and non-reservoir) by fluids. In this study, the 3D lithofacies probabilistic cubes of the first level and second-level level lithofacies were constructed by using the simulation method of well-seismic cooperative waveform indication. Afterwards, constrained by these probability cubes, the prestack geostatistical inversion was carried out to predict the spatial distribution of thin oil layers and water layers inside the thin reservoir. The major steps include: (1) Conduct rock physics analysis and lithofacies classification on carbonate reservoirs; (2) Construct the models constrained by two-level lithofacies; (3) Predict thin reservoirs in carbonates by prestack geostatistical inversion under the constraint of two-level lithofacies probability cubes. The prediction results show that through the two-level lithofacies-controlled prestack geostatistical inversion, the vertical and horizontal resolution of thin oil layers and water layers in carbonate reservoirs has been improved significantly, and the accuracy of thin oil reservoir prediction and the analyzing results of interwell oil layer connectivity have been improved significantly. Compared with the actual drilling results, the prediction results by 3D multi-level lithofacies-controlled inversion are consistent with the drilling results, and the details of thin carbonate reservoirs can be predicted. It has been proved that this method is reasonable and feasible. With this method, the prediction accuracy on thin reservoirs can be improved greatly. Compared with the conventional geostatistical inversion results, the 3D multi-level lithofacies-controlled inversion can improve significantly the vertical and horizontal resolution of prediction results of thin reservoirs and thin oil layers, and improve the reliability of interwell prediction results. For the prediction of thin carbonate reservoirs with serious heterogeneity, the 3D multi-level lithofacies-controlled inversion is an effective prediction method.

Flood-pot tests have been used for many years to determine the minimum residual oil saturation which would occur with 100 per cent water flood recovery efficiency. To evaluate the validity of such measurements, a study was made of core-analyses data from wells drilled prior to flooding and from wells drilled late in the flood life when operations were at or near the economic limit. The 19 wells in the latter category included in this study were limited to sands where "flushing of cores" was negligible. A comparison of oil saturations measured on fresh core samples in watered-out areas and companion flood-pot samples is shown. While the data indicate that average reservoir residual oil saturation exceeds the flood-pot residual value by 5 to 9 per cent of pore space, they also show that 5 per cent of the samples analyzed from watered-out areas contained no mobile oil and that 15 per cent of the samples contained only 1 to 2 per cent (pore volume) mobile oil. Correlations verifying these results are included and involve 165 cored wells from the Bartlesville formation in Oklahoma and Kansas, and the Bradford formation in Pennsylvania. The data further indicate that the commonly accepted concepts of the effects of permeability distribution on vertical conformance and the "dead areas" on sweep efficiency in pattern water flooding may not be applicable. Introduction In predicting the reserves and performance of a waterflood operation by both analytical and empirical methods, the minimum residual oil saturation after flooding must be determined. Core-analysis data often are used in obtaining this factor. One of two procedures can be followed:consider the oil saturation found by conventional core analysis after correction for shrinkage as the residual oil saturation to be expected from flooding with water, orperform flood-pot test to measure the residual and mobile oil saturations. In the latter, the mobile oil saturations determined from cores for certain areas are accepted as precisely those in the reservoir, although in a majority of pools it is recognized that some flushing of the core takes place and allowance is made for this through empirical factors. Thus, two opposite views are expressed; obviously, there is some merit to both. Spencer and Harding claim that, for determining residual oil saturations for conditions before and after flooding, reliability of core analysis depends on the properties and depth of the rock. These authors believe that during coring there is a tendency for the drilling-fluid filtrate to penetrate the formations ahead of the bit and displace oil. This action is supposed to be a minimum for formations having low vertical permeability and high reservoir pressures. However, the writers have observed that in pressure-depleted formations, or in formations containing oil with little or no gas in solution, little or no flushing occurs. For example, oil saturations greater than 50 per cent have been found in hundreds of cored wells in fields subjected to vacuum production for many years. It is believed that, in most productive formations, gas evolving from solution while the core is removed from the well is the principal reason for loss of oil rather than filtrate invasion during drilling. The following questions arise:Can a representative minimum residual oil saturation (immobile) after flooding be determined from conventional core-analysis liquid saturation tests, or should flood-pot tests be used?Are flood-pot test data usable in predicting waterflood reserves and performance? It was the object of this paper to answer these questions through a study of core-analyses data from watered-out areas. The study also includes data on wells drilled in the theoretically determined dead-area, or area supposedly not contacted by the injected water. It will be recalled that this concept originated from model and other research work performed by Muskat, Wyckoff, Botset and Muskat, and others. JPT P. 114^

Performance and gas breakthrough during CO 2 immiscible flooding in ultra-low permeability reservoirs

A study was carried out to establish the performance of a dragon well, or a well that dramatically changes inclination, in a thin oil rim reservoir. A well was simulated using commercial nodal analysis software by segmenting the inflow in multiple sections in order to incorporate the changes in trajectory and intersections with various reservoir layers. This simulation considered the pressure losses along the well bore for the varying trajectory, calculated for individual well sections, layers and combined commingle productivity and pressure profile; and was used to evaluate the well performance for a range of reservoir conditions (depletion, gas-oil ratio and water cut changes). This paper describes the approach used and key observations obtained from the results. A "segmented" inflow simulation approach can be used to model a dragon well. The method can be applied for modelling wells with sinusoidal trajectories in thin oil reservoirs. The results can be used to guide well and reservoir modellers in the concept assessment of this type of wells in field development studies. The model calculates the segment, layer, and total inflow and pressure profile in a complex trajectory. For the field and reservoir characteristics considered, the simulation indicated that the dragon well can produce through a wide range of conditions, including gas and water break-through. Good initial productivity can be expected from the well, but deteriorates fast with increasing GOR and water cut. As expected, the drawdown is not uniform along the trajectory; hence a drawdown stabilization strategy was addressed for the subject well through the use of a smart well completion. There is limited industry experience on sinusoidal or dragon wells modelling hence the results of the paper should be of interest to production technologists and reservoir engineers. This documented methodology can also be extended to simulation of complex horizontal or multilateral wells.