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Mehranfar, Reza (Schlumberger) | Marquez, Leonardo (Schlumberger) | Altman, Raphael (Schlumberger) | kolivand, Hassan (Schlumberger) | Orantes, Rodrigo (Schlumberger) | Espinola, Oswaldo (Schlumberger)
The objective of this work is to present a comprehensive workflow to optimize the value of a hydrocarbon asset evaluation project under high degrees of uncertainty. This workflow is applicable to both conventional and unconventional assets. However, because of the considerable level of subsurface uncertainty and high initial costs (mainly due to drilling and hydraulic fracturing operations), unconventional resources are good examples for demonstrating the benefits of the workflow. For the case of an unconventional asset, well spacing and perforation cluster spacing are usually the decision parameters that need to be optimized to increase its value.
The workflow begins with the construction of a representative base case single well gas simulation model for production history matching. Petrophysical, geological, geomechanical, stimulation, completions and production data are interpreted and analyzed together to better understand drivers that could be influencing the production. If this can be repeated with several wells in the block with sufficient production data, the process is enriched as so the level of confidence, as the range of history-matching parameters from these different wells across the block can be captured for sensitivity and uncertainty analysis. Several sets of sensitivities and uncertainty runs are then performed to get a probabilistic production profile in the presence of the most influential parameters. It is important to highlight that usually, the limited number of wells, short production histories, different dynamic behavior in neighboring blocks and the lack of necessary data to help understand well performance all contribute to the high uncertainty in predicting production.
Given the high cost of drilling and hydraulic fracturing and on the other hand the high gas price in Argentina, optimizing well spacing and cluster spacing are critical parameters in the process of unconventional resource evaluation considering the high degree of uncertainty.
One of the unanswered issues with steam applications is the wettability state during the process. Removal of polar groups from the rock surface with increasing temperature improves water wettability; however, other factors, including phase change, play a reverse role on it. In other words, hot water or steam will show different wettability characteristics, eventually affecting the recovery. On the other hand, wettability can be altered using steam additives. The mechanism of these phenomena is not yet clear. The objective of this work is to quantitatively evaluate the steam-induced wettability alteration in different rock systems and analyze the mechanism of wettability change caused by the change of the phase of water and chemical additives.
Heavy-oil from a field in Alberta (27,780 cP at 25°C) was used in contact angle measurements conducted on mica, calcite plates, and rock pieces obtained from a bitumen containing carbonate reservoir (Grosmont). All measurements were conducted at a temperature range up to 200°C using a high-temperature high-pressure IFT device. To obtain a comprehensive understanding of this process, different factors, including the phase of water, pressure, rock-type, and contact sequence were considered and studied separately.
Initially, the contact angles between oil and water were measured at different pressures to study the effect of pressure on wettability by maintaining water in the liquid phase. Secondly, the contact angle was measured in pure steam by keeping pressure lower than the saturation pressure. The influence of contacting sequence was investigated by reversing the sequence of generating steam and introducing oil during measurement. These measurements were repeated on different substrates. Different temperature resistant chemicals (surfactants and alkalis) were added to steam during contact angle to test their wettability alteration characteristics at different temperature and pressure conditions (steam or hot-water phases). The results showed that wettability of tested substrates is not sensitive to pressure as long as the phase has not been changed. The system, however, was observed to be more oil-wet in steam than in water at the same temperature, for example, in the case of calcite.
Analysis of the degree of the wettability alteration induced by steam (or hot-water) and temperature was helpful to further understand the interfacial properties of steam/bitumen/rock system and useful in the recovery performance estimation of steam injection process in carbonate and sand reservoirs.
Although various novel techniques were developed in reservoir engineering for estimation of hydrocarbons initially in place (HCIIP), conventional material balance still remains as one of the most reliable. Average reservoir pressure is critical input data for material balance, which is usually obtained by well shut-in. Nevertheless, this operation might be restricted due to economic and operational restrictions such as water production in gas wells.
In contrast, daily production data is commonly available and can be used to calculate the HCIIP by applying any production data analysis techniques such as the Dynamic Material Balance (DMB) method. The application of such methods to volumetric gas reservoirs and naturally fractured reservoirs resulted in accurate and reliable estimations. However, for water drive gas reservoirs, where the water influx term should be introduced into the iterative process, research and field case applications are limited.
This paper presents an extension to the DMB technique to water-drive gas reservoirs. A simultaneous estimation of the Original Gas-in-place (OGIP) and the water influx term is achieved by coupling the DMB technique with the Fetkovich aquifer model. Average reservoir pressure estimation can also be attained as a result of the coupled method.
Results were validated by means of numerical simulation on a synthetic model and a field study case. Synthetic production data was generated by a commercial simulator and then analized with the coupled method. The calculated OGIP, water influx volumes and average reservoir pressure resulted comparable to simulator output as they presented a low relative error. Furthermore, application of the coupled method to the field study case yielded comparable results to those obtained by volumetric method.
Low Salinity Water Flooding (LSWF) is an emergent technology developed to increase oil recovery. Many laboratory tests of LSWF have been carried out since the 1990's, but modelling at the reservoir scale is less well reported. Various descriptions of the functional relationship between salt concentration and relative permeability have been presented in the literature, as have the differences in the effective salinity range over which salt content takes effect. This paper focuses on these properties and their impact on the fractional flow of LSWF. We present observations that help characterise the flow behaviour in a more general form, simplifying the interpretation of results. We explain how numerical or physical diffusion of salt affects the velocity of the waterflood front, and how this can be predicted from fractional flow analysis.
We have considered various linear and non-linear shapes of the function relating salinity to relative permeability and different effective salinity ranges using a numerical simulator applied at the reservoir scale. The results are compared to fractional flow theory in which both salt and water movement is assumed to be shock-like in nature.
We observe that diffusion of the salt front is an important process that affects the fractional flow behaviour depending on the effective salinity range. The simulator solution matches the analytical predictions from fractional flow analysis under the condition that the mid-point of the effective salinity range is at the mid-point between the formation and injected salt concentrations. However, an effective behaviour similar to adsorption/desorption occurs when these mid-point concentrations are not coincidental. The outcome is that the fronts representing high and low salinity water travel with altered velocities and at different saturations.
We find that we can predict this behaviour from the input data alone as an augmented form of the fractional flow theory including the concept of retardation or acceleration as occurs for adsorption and desorption for other injectants. We use the analytical solution to the advection-diffusion equation and find that the changes in behaviour depends on the Peclet number.
The result of our work is that we have produced an updated form of the fractional flow model of LSWF, to include the impact of salt front diffusion on the movement of fluids. A new factor is introduced, similar to adsorption in polymer flooding. We have developed a new mathematical formula, empirically, to estimate the magnitude of this factor. The new form can be used to modify the effects that numerical or physical diffusion have on the breakthrough times of high and low salinity water fronts during LSFW. This will improve predictive ability and also reduce the requirement for full simulation.
Primary gas recovery for a volumetric reservoir ends when the reservoir pressure declines below the value required to flow gas to the surface at the sales line pressure. Secondary gas recovery techniques can then be employed to increase the recovery, once they are economically viable. The most common of these techniques is gas compression; but another feasible technique, which is rarely ever explored, is water injection. This paper evaluates the incremental benefit of water injection in a conventional gas reservoir when compared to gas compression.
This was achieved through analytical simulation of a retrograde gas-condensate reservoir located in the Columbus Basin off the south-east coast of Trinidad. The techniques which were applied here have been historically used in the waterflooding of oil reservoirs, and were tailored in this novel case for the use in gas reservoirs. The reservoir evaluated is a faulted sandstone formation of good quality that is divided into two hydrocarbon bearing segments. In one of the segments, production ended due to a decline in the reservoir pressure, indicating the end of primary gas recovery. Both reservoir and well modelling were done using the IPM Suite. In this paper, the scope was narrowed to focus on the application of analytical simulation as a means of quickly screening various production scenarios. Simple economic evaluations were done using the University's methodology and current economic metrics, with the operational and capital expenditures derived from offshore projects by operator companies within Trinidad.
The findings showed that while gas compression generated significantly higher internal rates of return, water injection provided similar net cash flows. Unlike gas compression, which improves the recovery by allowing the reservoir to produce at a lower tubing head pressure than the sales line pressure; water injection increases the reservoir pressure by filling the voidage space created as a result of the depletion process. Thus, the feasibility of water injection is dictated largely by the volume of water which is required, since gas is highly compressible.
The primary value of water injection as a secondary gas recovery technique stems from the use of high water rates from nearby producing wells under aquifer drive, which would otherwise be shut-in. The technique can also be managed as a water disposal option for adjacent fields, thus reducing company expenditure on treating the produced water from the wells mentioned above.
A mechanistic foam modeling technique based on bubble population balance, which honors three different foam states (weak-foam, strong-foam, and intermediate states) and two steady-state strong-foam flow regimes (high-quality regime and low-quality regime of the strong-foam state), is developed to investigate how CO 2 foam behaves rheologically and propagates in a petroleum reservoir. The model parameters are first obtained from a fit to existing laboratory coreflood experimental data, and then the mechanistic model is applied to different types of CO 2 foams, ranging from gaseous to supercritical CO 2 foams, represented by various mobilization pressure gradients. The results from the fit to existing coreflood data show that a reasonable match can be made satisfying multiple constraints such as hysteresis exerted by three foam states, non-Newtonian flow behavior caused by gas trapping and shear thinning rheology, and bubble stability at different capillary pressure environments. Among different sets of input parameters resulting in equally nice fits, an additional experimental data (for example, the onset of foam generation by increasing the total flow rate step by step at fixed foam quality) can help narrow down the range of input parameters further. When applied to field-scale scenarios, supercritical CO 2 foams requiring low mobilization pressure gradient propagate much further than gaseous CO 2 foams, far enough to make use of supercritical CO 2 foams promising in the fields. This in turn proves theoretically why supercritical CO 2 foams should be preferred in the field compared to gaseous CO 2 foams. The model shows foams in the low-quality regime can propagate longer distance than foams in the high-quality regime because of better foam stability at lower capillary pressure environment.
The assumption of constant rate production, which is often invalid for the extended period of production, is one of the fundamental premises for current analytical approaches of temperature transient analysis. This work addressed this issue by introducing novel analytical approaches to model temperature signals under variable rate conditions. The specific methods share underlying theories of superposition principle and production rate normalization from pressure transient analysis. With adapting these methods, cases with complex production history are modelled using analog cases producing with constant rate. The analytical approach validation is performed by graphically and quantitative estimation of reservoir properties compared with synthetic temperature data. The estimation outputs of these methods include permeability, porosity, drainage area, and damaged zone properties, which are the application combinations from temperature transient analysis and reservoir limits testing. Monitoring well surveillance is extended to variable rate production in this paper. A case documented in the literature is addressed by this temperature analysis for which decent reservoir characterization results are obtained. The temperature analysis proposed in this paper extends the scope of temperature transient analysis to complex production constraints and demonstrates convincing results for practical purposes.
Integrated asset modeling has been used for the last decade with a wide technical application covering different challenges from field development to production optimization. Besides supporting the FEEDS and FEL studies for different purposes. Moreover, the technology has evolved in terms of integration and dynamic or transient simulation has been added as an extra element expanding the possibility to cover different challenges and workflows. The objective of this paper is to show how this dynamic integration (Dynamic integrated asset modeling) was applied to a common problem of several reservoirs that produce water and gas under different dynamic mechanisms (injection, aquifer and gas cap) to understand, from the reservoir perspective, the effects of gas and water conning over the entire production system.
The methodology applied was using a refined sector model solved with numerical simulation and coupled with a transient multiphase flow simulator to see how pressure drop affect the contacts level and shape based on the petrophysical properties and under different production scenarios and generate different graphics to see how this phenomenon behaves. Besides a comparison with all the most analytical correlations used in the literature to identify gas and water conning was performed to see the differences among them and with this dynamic integrated approach. On the other hand, for the production side this coupled model was applied to an offshore facility to see these reservoir effects in the transport system and how they impact in the pipeline and riser due to this abrupt entrance of gas and water changing the flow conditions, flow patterns, pressure drop and creating some instabilities in the separators caused by severe slugging.
The results of this analysis were very useful to understand the total production systems (reservoir-surface) behavior, predict the gas and water breakthrough, establish the critical rates to avoid these problems and see how the results differ in some cases with the common analytical correlations. Specific conditions in the pipeline and riser were established to quantify the slugging problems and evaluate different alternatives to eliminate the instabilities through proposing different scenarios such as gas injection in the riser, top side choking, etc. Application of this integrated approach has been very beneficial in recognizing the source of the problem, offer proper and feasible solutions in development and operational phases. In addition, validating and reducing uncertainty of related literature correlations and give to the production and reservoir engineers a quick and reliable way to know the critical rates that can support the decision-making process.
The objective of this Technical Paper is to show the experiences and challenges in the design and execution of an extended reach well in unconsolidated sands carried out by Pluspetrol Bolivia Corporation in the Tacobo-Curiche Area. Due to surface obstacles (bed of the Rio Grande river) was proposed the drilling of a directional well which trajectory had to pass through two objectives: 1570 m Horizontal Displacement (HD) at 770 mTVD and 2345 mHD at 1171 mTVD, with the following conditions: 1st.- unconsolidated sands, 2nd.- channel of the river and 3rd.- superficiality of the objectives. The main objectives set for this project were: 1. Reach the targets in the required position.
Gas condensate reservoirs constitute a significant portion of global hydrocarbon reserves. In these reservoirs, liquids develop in the pore space once bottomhole pressure falls below dew point. This results in the formation of a liquid bank near the wellbore region which decreases gas mobility, which then reduces gas inflow. In such complex reservoirs, it is important to correctly describe PVT impacts, adjustments to well test analysis and inflow performance, and then combine all effects in the reservoir analysis. The literature contains many references to individual adjustments of PVT analysis, well testing, or inflow performance for gas condensate reservoirs, but few studies demonstrate the complete workflow for reservoir evaluation and production forecasting in gas condensate fields. This research uses a field case study to demonstrate an integrated workflow for forecasting well deliverability in a gas condensate field in North Africa.
The workflow incorporates a description of the retrograde behavior that impact the well deliverability. The workflow begins with the interpretation of open-hole log data to identify the production interval net pay and to estimate petrophysical properties. A compositional model is developed and matched to actual reservoir fluids. Several gas condensate correlations are used to obtain the gas deviation factor and gas viscosity in order to count the change in gas properties with respect to pressure. Transient pressure analysis is described and used to identify reservoir properties. Inflow performance relationships (IPRs) are analyzed using three types of back pressure equations. The workflow integrates all data in a numerical simulation model, which includes the effect of bottom water drive.
Results show that in this field case study, reservoir behavior is composite radial flow with three regions of infinite acting radial flow (IARF). Using compositional simulation, it is found that the fluid sample for this field is a lean gas condensate since the liquid drop-out represented 1% of the maximum liquid drop-out. In addition, liquid drop-out increases by 0.1% for every 340 psi drop in reservoir pressure, which reduces the AOF by 3.4%.
The results provided in this case study demonstrate the importance of an integrated workflow in predicting future well performance in gas condensate fields. The study demonstrates how to implement the workflow in managing or developing these types of reservoirs.