Water-alternating-gas Cycles Research Articles

Modeling and Simulation of Alternative Injections of CO2 and Water into Porous Carbonate Formations

Water alternating gas (WAG) technique is used in the petroleum industry to inject carbon dioxide (CO2) into underground formations either for sequestration or enhanced oil recovery (EOR) processes. CO2 injection causes reactions with formation brine or aquifer and produces carbonic acid, the acid dissolves calcite and changes flow behavior significantly. Modeling and investigating effects of CO2 injection into carbonate formations during WAG processes, investigating parameters related to chemical reactions between reservoir rock and injecting fluid and also better understanding of the process theory for future experiments are the most important goals of this paper. To achieve these experimental data were used. Changes of output calcium concentration from a calcite core sample during three WAG cycles have been studied in laboratory works. The sample is modeled as a medium consisting of a set of capillary pipes and two pore size distribution models are used. Plug flow model and mass conservation law are used for modeling and Darcy law and Hagen-Poiseuille equation are also used to determine characteristics of the porous model. The model is built for linear, miscible and one-dimensional flow. The results show that experimental and model data coincide well in the first and second cycles of both porous models however; they are not coincided in the third cycle. It is because of precipitation and dissolution that cause permeability alternations. Results of the two porous models are compared also.

Accurate Modelling of Pore-Scale Films and Layers for Three-Phase Flow Processes in Clastic and Carbonate Rocks with Arbitrary Wettability

Three-phase flow is a key process occurring in subsurface reservoirs, for example, during $$\text{ CO }_2$$ sequestration and enhanced oil recovery techniques such as water alternating gas (WAG) injection. Predicting three-phase flow processes, for example, the increase in oil recovery during WAG, requires a sound understanding of the fundamental flow physics in water- to oil-wet rocks to derive physically robust flow functions, i.e. relative permeability and capillary pressure. In this study, we use pore-network modelling, a reliable and physically based simulation tool, to predict the flow functions. We have developed a new pore-scale network model for rocks with variable wettability, from water- to oil-wet. It comprises a constrained set of parameters that mimic the wetting state of a reservoir. Unlike other models, it combines three main features: (1) A novel thermodynamic criterion for formation and collapse of oil layers. The new model hence captures wetting film and layer flow of oil adequately, which affects the oil relative permeability at low oil saturation and leads to accurate prediction of residual oil. (2) Multiple displacement chains, where injection of one phase at the inlet triggers a chain of interface displacements throughout the network. This allows for the accurate modelling of the mobilisation of many disconnected phase clusters that arise, in particular, during higher order WAG floods. (3) The model takes realistic 3D pore-networks extracted from pore-space reconstruction methods and CT images as input, preserving both topology and pore shape of the sample. For water-wet systems, we have validated our model with available experimental data from core floods. For oil-wet systems, we validated our network model by comparing 2D network simulations with published data from WAG floods in oil-wet micromodels. This demonstrates the importance of film and layer flow for the continuity of the various phases during subsequent WAG cycles and for the residual oil saturations. A sensitivity analysis has been carried out with the full 3D model to predict three-phase relative permeabilities and residual oil saturations for WAG cycles under various wetting conditions with different flood end-points.

Experimental Investigation of Immiscible Gas Process Performance for Medium Oil

Abstract Immiscible CO2 injection is a potentially viable method of enhanced oil recovery (EOR) for medium oil reservoirs in southwestern Saskatchewan. The relatively high reservoir pressures could result in a large extent of CO2 dissolution, significant oil viscosity reduction and oil swelling. Laboratory corefloods were used to compare the performance of different modes of CO2 injection into a medium-gravity oil system. The following methods were compared: injection of a single CO2 slug chased by water, simultaneous injection of water/CO2, and different water-alternating-gas (WAG) cycles. The results indicate that both a single CO2 slug and the first WAG cycle in a series produced oil very efficiently, possibly owing to good gas/oil contact at the relatively high residual oil saturation at this stage. The simultaneous injection of water/CO2 was not as effective as a single CO2 slug, possibly because the co-injected water shielded the oil from being contacted by the gas. Among the four runs, a coreflood with four WAG cycles recovered the most incremental oil—20.58% initial oil in place (IOIP)—while the co-injection process produced the least (8.91% IOIP). This experimental study suggests that the immiscible CO2 EOR process is viable for medium oil reservoirs with relatively high pressures, and that proper process application is important for maximizing additional oil production. Introduction Miscible/immiscible CO2 flooding is an increasingly popular EOR technique. So far, most of the CO2 miscible/immiscible processes have been applied in light oil reservoirs, and there has been little application in medium oil reservoirs. The in-place resources of medium oils, defined as 20 - 30°API, in Saskatchewan are estimated at up to 1,338 × 106 m3 (8.42 billion barrels)(1). Most of these reservoirs are characterized by thin pay (2 to 10 metres in thickness) and shaly sand, and they have been under production for over four to five decades. The estimated average recovery by conventional waterflood, as listed in Table 1, is only approximately 23% IOIP because this method has generally exhibited early water breakthrough and high water cuts owing to the unfavourably high water-to-oil mobility ratio. By adapting miscible/immiscible CO2 flooding technologies that have matured in light oil applications, the immiscible CO2 process is potentially viable for recovering additional oil from these medium oil reservoirs if we can improve its displacement and sweep efficiency(2).

Improved Reservoir Management With Intelligent Multizone Water-Alternating-Gas (WAG) Injectors and Downhole Optical Flow Monitoring

Summary A four-zone intelligent water-alternating-gas (WAG) injector was installed at the Statoil Veslefrikk Field in the North Sea in May 2004. The completion includes one on/off and three variable downhole chokes for controlling injection rate into each of the four zones. The completion also includes three downhole optical flow-meters and three optical pressure and temperature gauges. Measurement of surface injection rate and the rate from each of the three flowmeters provides real-time measurement of injection rate into each zone, regardless of choke positions. The well is on a WAG cycle in which one zone is primarily intended for gas injection and the other three zones are primarily intended for water injection. Therefore, equipment that can control and measure water flow and gas flow with no changes in hardware was critical for the success of this installation. The combination of downhole chokes and flowmeters allows full control and monitoring of zonal injection rates and has proved to be a valuable tool for managing reservoir pressures and optimizing production. After more than 1 year of operation during water injection, all the valves and the optical monitoring equipment are functioning satisfactorily. It is estimated that up to half of the well's value creation during its expected lifetime is because of the DIACS (Downhole Instrumentation and Control System) installation.

Three-Phase Flow WAG Processes in Mixed-Wet Porous Media: Pore-Scale Network Simulations and Comparison With Water-Wet Micromodel Experiments

Summary The pore-scale physics of water-alternating-gas (WAG) injection is still not completely understood. We summarize the development of a 3D pore-scale network simulator for capillary-dominated three-phase flow in media where wettability varies from pore to pore. Reduction of phase continuity has required incorporation of multiple displacements for mobilization of disconnected phase clusters. WAG processes have been simulated, for which saturation paths are recorded along with statistics of phase pore occupancies and displacement mechanisms, showing the importance of multiple displacements. Furthermore, using 2D network simulations, we have modeled the WAG floods following primary drainage and initial waterflooding in a water-wet micromodel. Good qualitative agreement is found, in particular with respect to the displacement mechanisms occurring during the WAG cycles.

Pore-scale modelling of three-phase flow in mixed-wet porous media: multiple displacement chains

A three-dimensional (3D) pore-scale network simulator is presented for modelling capillary-dominated three-phase flow in porous media where the wettability varies from pore to pore. The physics of weakly wetted systems has been included by allowing a pore to have any contact angle and, indeed, for each pore to have a different contact angle from a chosen distribution. An important complication arising from weakly wetting conditions is the absence of wetting films, which strongly reduces the continuity of the phases throughout the network. This reduction in phase continuity implies that during water-alternating-gas (WAG) injection processes a large number of phase clusters may form, that are disconnected from both inlet and outlet. Mobilisation of these clusters can happen through so-called multiple displacement chains, which involve a string of different phase clusters between inlet and outlet. We have explored the impact of these multiple displacement chains on WAG flow processes and the underlying three-phase flow mechanisms in a mixed-wet porous medium with the larger pores oil-wet. Assuming total absence of wetting films, we have varied the connectivity of the network (co-ordination number and dimension), the size of the network, the allowed maximum length of the displacement chains and the number of WAG cycles. The results are presented not only in terms of saturations and oil recovery, but also through statistics per flood of the length and type of displacement chains, the pore occupancy and through snapshots of the actual flood distributions (2D). From the simulations we conclude that for highly connected networks a steady state is reached after only a few WAG cycles, during which oil production ceases. However, in this state oil continues to be moved around within the network as a result of multiple displacement chains. The maximum allowed chain length has a substantial effect on the WAG saturation path, although the presence of longer chains during higher order WAG cycles is reduced for smaller networks and for networks with higher connectivity. For the investigated wettability state of the porous medium, four prevailing types of displacements emerge during each water flood and four different types emerge during each gas flood. When suppressing chains longer than two displacements in each flood one type disappears. Finally, we have listed some ways in which the predictions from the simulations may be tested experimentally both in core material and also in 2D micromodels. The latter type of experiments are particularly attractive, since lengths and types of displacement chains can be observed and counted directly.

A Field Test of Nitrogen WAG Injectivity

Summary A one-well field test of nitrogen WAG (water alternating gas) injectivity was conducted to determine whether a reduction in water injectivity would occur after injection of nitrogen. A 40% reduction was observed immediately after nitrogen injection. Following three short WAG cycles, water injectivity increased to its pretest level with injection of a large volume of water. Introduction The Jay/LEC field in Florida and Alabama is producing under unitized waterflood operations. Several papers describe this field's historical development. The field test described in this paper was undertaken as part of an engineering evaluation of injecting nitrogen and water alternately into the Jay/LEC field Smackover reservoir to determine the effect on a miscible gas tertiary process. Several operators of miscible WAG injection projects have encountered a reduction in water injectivity after gas injection. in two projects, water injectivity decreased significantly and operators speculated that either the precipitation of asphaltenes, trapped residual gas saturation, or movement of fine granules of reservoir rock caused declines in injectivity. These projects were unable to achieve oil production rates forecast because more than the anticipated time was required to inject planned water volumes. If a reduction in water injectivity occurs because of trapped carbon dioxide saturation, the high solubility of carbon dioxide in water should allow water injectivity to increase rapidly during the succeeding water injection cycle. In addition, injection wells may experience a slight increase in permeability and porosity due to the solution of carbon dioxide in water forming a weak acid. In a nitrogen WAG project, the low solubility of nitrogen in water will prevent the trapped gas saturation from changing significantly during the water injection phases of WAG injection. Several documented WAG projects using low-water-soluble gases have observed significant reductions in water injectivity, while significant reductions in water injectivity when high-water-soluble gases are used are not documented. Laboratory experiments were performed with cores from the Jay/LEC field in an attempt to determine whether a seduction in water injectivity would occur if nitrogen and water were injected alternately into the Smackover reservoir. The results of these experiments were inconsistent. Changing rock wettability and movement of formation fines may have contributed to the inconsistent results. Since laboratory experiments to provide a basis for predicting field injectivity were unsuccessful, and in light of reported poor field performance, a field test was carried out to determine whether nitrogen WAG injection into the Jay/LEC Smackover reservoir would reduce water injectivity. During the field test initiated in Aug. 1978, reservoir injectivities and transmissibilities of water and nitrogen were observed during three cycles of nitrogen followed by water injection into a Jay/LEC field well. The conventional Homer analysis interpretation technique did not provide definitive solutions. A technique consisting of plotting transmissibility vs. square root of shut-in time provided a useful tool for observing fluid banks in the reservoir and evaluating changes in water and gas injectivities. Design To ensure the selection of a representative injection well and simplify interpretation of bottom hole pressure measurements, the following criteria were established.Reservoir development in the injection well should be limited to one relatively thin zone.The ratio of permeability-thickness to injection rates during the injectivity test should be representative of rates in injection wells if a field wide project is carried out JPT P. 266^