Initial rate and decline are the two main parameters defining the economics of unconventional shale oil development. To improve economics, companies drill longer horizontal wells with more than twenty equidistant stages, different completion strategies and various additives such as surfactants and nano surfactants. This procedure evolves to factory mode in which tasks are optimized in timing and performance without attention to the matrix aspects of improving the recovery. Here, we report the design of a mutual solvent injection pilot in the Vaca Muerta unconventional reservoir during the completion of four unconventional shale oil wells. Reducing
Vaca Muerta has been long regarded as a water wet shale because of the limited water backflow post-fracking job. Alternating water injection was implementing assuming that the well productivity is driven by spontaneous imbibition, but this strategy has been unsuccessful as capillary pressure hysteresis drives this mechanism. We started studying Vaca Muerta from the rock microstructure using energy-dispersive spectrometry and focused gallium Ion Beam ablation FIB SEM images. The microstructure varied widely from millimeters in the same plug which could be expected because in shale rocks millimeters represent more years of deposition than in a conventional reservoir. We identified intercalations of massive water wet zones and strongly oil wet zones in the Vaca Muerta kitchen zone. The oil wet intercalations have high porosity and adsorption isotherm indicating 100 to 1000 times more permeability than the water wet zone. The water wet intercalations are highly saturated with water, and on the contrary, the oil wet intercalations are highly saturated with oil. The pilot designed consisted of four wells in which we will test different injection concentrations but keeping the total mass constant. In this manner, we will estimate the volume contacted by the solvent.
The laboratory protocol indicates a large percentage of macro and meso-pores. We implemented the dimethyl-ether injection which changes the interfacial tension, viscosity and wettability and we obtained the modified relative permeabilities which were the injection of dimethyl ether at 30% concentration along with the hydraulic fracture stimulation stages doubled the initial oil production rate.
The pilot consisted of five wells in which we will test different injection concentrations but keeping the total mass constant. In this manner, using the numerical simulation, we will estimate the volume contacted by the solvent.
Intercalations of high porosity high permeabilities zones in which the injection of a mutual solvent that reduces viscosity and could change wettability in oil wet/water-wet Vaca Muerta improving matrix connectivity.
Lin, Qingyang (Imperial College London) | Alhammadi, Amer M. (Imperial College London) | Gao, Ying (Imperial College London) | Bijeljic, Branko (Imperial College London) | Blunt, Martin J. (Imperial College London)
We combine steady-state measurements of relative permeability with pore-scale imaging to estimate local capillary pressure. High-resolution three-dimensional X-ray tomography enables the pore structure and fluid distribution to be quantified at reservoir temperatures and pressures with a resolution of a few microns. Two phases are injected through small cylindrical samples at a series of fractional flows until the pressure differential across the core is constant. Then high-quality images are acquired from which saturation is calculated, using differential imaging to quantify the phase distributions in micro-porosity which cannot be explicitly resolved. The relative permeability is obtained from the pressure drop and fractional flow, as in conventional measurements. The curvature of the fluid/fluid interfaces in the larger pore spaces is found, then from the Young-Laplace equation, the capillary pressure is calculated. In addition, the sequence of images of fluid distribution captures the displacement process. Observed gradients in capillary pressure – the capillary end effect – can be accounted for analytically in the calculation of relative permeability.
We illustrate our approach with three examples of increasing complexity. First, we compare the measured relative permeability and capillary pressure for Bentheimer sandstone, both for a clean sample and a mixed-wet core that had been aged in reservoir crude oil after centrifugation. We characterize the distribution of contact angles to demonstrate that the mixed-wet sample has a wide range of angle centred, approximately, on 90°. We then study a water-wet micro-porous carbonate to illustrate the impact of sub-resolution porosity on the flow behaviour: here oil, as the non-wetting phase, is present in both the macro-pores and micro-porosity. Finally, we present results for a mixed-wet reservoir carbonate. We show that the oil/water interfaces in the mixed-wet samples are saddle-shaped with two opposite, but almost equal, curvatures in orthogonal directions. The mean curvature, which determines the capillary pressure, is low, but the shape of the interfaces ensures, topologically, well-connected phases, which helps to explain the favourable oil recovery obtained in these cases.
We suggest that the combination of imaging and flow experiments – which we call iSCAL – represents a compelling development in special core analysis. This methodology provides the data traditionally acquired in SCAL studies, but with insight into displacement processes, rigorous quality control, and flexibility over sample selection, while generating detailed datasets for the calibration and validation of numerical pore-scale flow models.
The reliability of measurements of relative permeabilities and capillary pressures is an important issue for reservoir engineering. Proper sampling of rocks for measurements is most important for ensuring the reliability of relative permeability and capillary pressure data. If samples are obtained improperly, costly and reliable methods for measuring rock/fluid properties may no longer be necessary or suitable. The goal of sampling should be to avoid or minimize mechanical and chemical damage to the rock. With all of these opportunities, some damage is inevitable. It should be obvious that reliable data require good measurement methods and correct treatment of the data obtained.
Relative permeability and capillary pressure defined capillary pressure as the difference in pressure across the interface between two phases. With Laplace's equation, the capillary pressure Pcow between adjacent oil and water phases can be related to the principal radii of curvature R1 and R2 of the shared interface and the interfacial tension σow for the oil/water interface: The relationship between capillary pressure and fluid saturation could be computed in principle, but this is rarely attempted except for very idealized models of porous media. Methods for measuring the relationship are discussed in Measurement of capillary pressure and relative permeability. For this example, water is the wetting phase, and gas is the nonwetting phase. As shown in Figs. 2 and 3, a wetting phase spreads out on the solid, and a nonwetting phase does not.
Water is the wetting phase. Figure 1.5 – Primary drainage, imbibition, and secondary drainage for an oil/water system in which the oil and water wet the solid surface equally. Figure 1.6 – Primary drainage and imbibition for unconsolidated dolomite powder (the lines merely connect the data). These authors wrote capillary pressure as the negative of Eq. 4 because oil was the wetting phase for most of the tests. The legend gives contact angles measured through the water phase (in degrees). Leverett and coworkers, based on the evaluation of gas/water capillary pressure data for drainage and imbibition in unconsolidated sands, proposed the following definition: ....................(15.6) The function j(Sw), defined in Eq. 15.6, is known to many as the "Leverett j-function." The j-function is obtained from experimental data by plotting against Sw. The combination is often considered an estimate of the mean hydraulic radius of pore throats.
There are many possible causes of formation damage. In addition to the numerous sources identified in separate articles (see See Also section below), other, less common causes include emulsions and sludges, wettability alteration, bacterial plugging, gas breakout, and water blocks. The presence of emulsions at the surface does not imply the formation of emulsions in the near-wellbore region. Most often, surface emulsions are a result of mixing and shearing that occur in chokes and valves in the flow stream after the fluids have entered the well. Such emulsions usually have a higher viscosity than either of the constituent fluids and can result in significant decreases in the ability of the hydrocarbon phase to flow.
At the pore level (i.e., where the water and oil phases interact immiscibly when moving from one set of pores to the next), wettability and pore geometry are the two key considerations. The interplay between wettability and pore geometry in a reservoir rock is what is represented by the laboratory-determined capillary pressure curves and water/oil relative permeability curves that engineers use when making original oil in place (OOIP) and fluid-flow calculations. This article discusses these basic concepts and their implications for initial water- and oil-saturation distribution, relative permeability, and how initial gas saturation will affect water/oil flow behavior. Figure 1 is a schematic diagram of the water/oil displacement process. Wettability is defined in terms of the interaction of two immiscible phases, such as oil and water, and a solid surface, such as that of the pores of a reservoir rock.
Dick, Michael (Green Imaging Technology) | Veselinovic, Dragan (Green Imaging Technology) | Green, Derrick (Green Imaging Technology) | Scheffer-Villarreal, Aimee (ConocoPhillips) | Bonnie, Ronald (ConocoPhillips) | Kelly, Shaina (ConocoPhillips) | Bower, Kathleen (ConocoPhillips)
Wettability is a crucial petrophysical parameter for determining accurate production rates in oil and gas reservoirs and may be especially impactful in predicting the extent of injected fluid imbibition and resultant drainage in the vicinity of hydraulic fractures within unconventional reservoirs. However, traditional industry standard wettability measurements (Amott test and USBM) often fall short when performed on unconventional samples. In this work, we adapt the existing T2-based NMR wettability index (NWI) measurement to unconventional samples in order to provide robust wettability measurements for tight rocks.
Wettability describes the affinity of a fluid to a solid surface and is dependent on rock properties such as mineralogy, aging, and brine and hydrocarbon composition. As a system always seeks to minimize surface energy toward equilibrium, whether a surface is hydrophobic (prefers to contact non-aqueous fluid molecules, usually of lesser polarity than water) or hydrophilic (prefers water) will determine the native state distribution of brine and hydrocarbon as well as the dynamic behavior of these saturations. It is well known in conventional reservoirs that wettability can greatly influence the character of relative permeability curves and production. Conventionally, water wet is the preferred state for petroleum exploration, as water will reside in the smallest pores and hydrocarbons in the larger pores and apertures, but many successful reservoirs have mixed (or intermediate) wettability. The tight pore structures of unconventional reservoirs are also sensitive to wettability controls, if not governed by them due to strong capillarity; however, the influence of wettability on matrix and matrix-fracture transport during and after hydraulic fracturing is not as well understood as in (or for?) conventional reservoirs. Learnings on the role of wettability in unconventional rocks may render useful information for the design of well completion and enhanced oil recovery strategies.
A wettability assessment such as NWI may assist with testing wettability states and controls in tight rocks in a quantitative matter. Recall that a wettability index of 1 is very water wet, −1 is very oil wet, 0 is neutral/mixed wet, and values close to 0 are weakly oil or water wet. This research demonstrates the utilization of the NWI technique on two twin sets of South Texas unconventional core plugs expected to have differing wettability due to significantly higher organic matter content in one of the sample sets. The samples, generally labeled sample 2-PX and 7-PX, are from the same well in producing acreage, but different lithological units. Sample 2-PX is a chalk and sample 7-PX is a marl; the latter has significant organic matter and clay content. Some basic petrophysical properties of these samples are listed in Table 1.
Al-Rudaini, Ali (Heriot-Watt University) | Geiger, Sebastian (Heriot-Watt University) | Mackay, Eric (Heriot-Watt University) | Maier, Christine (Heriot-Watt University) | Pola, Jackson (Heriot-Watt University)
We propose a workflow to optimise the configuration of multiple interacting continua (MINC) models and overcome the limitations of the classical dual-porosity model when simulating chemically enhanced oil recovery processes. Our new approach captures the evolution of the concentration front inside the matrix, which is key to design a more effective chemically enhanced oil recovery projects in naturally fractured reservoirs. Our workflow is intuitive and based on the simple concept that fine-scale single-porosity models capture fracture-matrix interaction accurately and can hence be easily applied in a commercial reservoir simulator. Results from the fine-scale single-porosity system are translated into an equivalent MINC method that yields more accurate results than the classical dual-porosity model or a MINC method where the shells are arbitrarily selected.
Our approach does not require the tuning of capillary pressure curves ("pseudoisation"), diffusion coefficients, MINC shells, or the generation of recovery type curves, all of which have been suggested in the past to model more complex recovery processes. A careful examination of the fine-scale single-porosity model ("reference case") shows that a number of nested shells emerge, describing the advance of the concentration and saturation fronts inside the matrix. The number of shells is related to the required degree of refinement, i.e. the number of shells, in the improved MINC model. Using the results from a fine-scale single-porosity simulation to set up the shells in the MINC model is easy and requires only simple volume calculations. It is hence independent of the chosen simulator.
Our improved MINC method yields significantly more accurate results compared to a classical dual-porosity model, a MINC method with equally sized shells, or a MINC model with arbitrarily refined shells for a number of recovery scenarios that cover a range of matrix wettabilities and permeabilities. In general, improved results can be obtained when selecting five or fewer shells in the MINC. However, the actual number of shells is case-specific. The largest improvement is observed for cases when the matrix permeability is low.
The novelty of our approach is the easy-to-use method to define shells for a MINC model to predict chemically enhanced oil recovery from naturally fractured reservoirs more accurately, especially in cases where the matrix has low permeability. Hence the improved MINC method is particularly suitable to model chemical EOR processes in (tight) fractured carbonates.
The Alvheim field, offshore Norway, has subsea wells with long horizontal branches completed with sand screens. After 10 years of production, water production starts to constrain the oil production. Mechanical water shut-off is impossible in these wells, hence other methods are of interest. In a well workover in 2013, two high-viscous polymer pills were bull-headed and squeezed into the reservoir. The well productivity was reduced with around 50% while the water-cut dropped and pointed to potentially 3 mmstb of extra oil recovery. A research study was initiated with the objectives to understand the changed well performance and if polymer bull-heading can be a future method to reduce water production and enhance oil production.
An experimental laboratory program started with filtration tests of polymer solutions based on the polymer used in the well operation. Core flood experiments were performed by injecting polymer into two parallel mounted cores, then back producing these individually with either water or oil. Several combinations of parallel cores were tested with polymer injection: high vs. low permeability, high oil saturation vs. low oil saturation, outcrop sandstone vs. Alvheim core, as well as two different polymer versions.
The polymer recipe as used in the well operation showed to plug standard filters with filter size larger than the reservoir pore sizes but did not plug the cores. The polymer recipe as used in the well gave a better disproportionate permeability reduction (DPR) than the alternative polymer variant with similar viscosity. A theoretical model for the shear rate in the porous media matched the experimental measured data excellent. The core results show a stable permeability reduction factor of 100-450 for water, while only a factor 2-10 and decreasing with time for oil. The achieved DPR ratio of 45-80 is better than the trend from earlier published results.
The DPR as measured in the laboratory was next integrated in the reservoir model as part of the history match of the treated well. The Alvheim field has several reservoir zones separated with thin shales, and this reservoir zonation seems key for this EOR method to work.
The laboratory work, the reservoir studies and the field experience all point to a possible robust and simple EOR method for Alvheim and similar oil fields. The polymer seems to act as a "magic filter", allowing oil to pass while not water. Future work includes more research and maturing a new polymer pilot on Alvheim.