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Fractures often influence production behaviour in hydrocarbon reservoirs, yet the pressure transients observed in the wells may not show the conventional well-test signatures. In this case, the effect of fractures on production would be misinterperted or even completely missed. Fracture networks are commonly multi-scale and properties including aperture (or conductivity), length, connectivity and distribution vary greatly within a reservoir. The heterogeneous nature of fractured reservoirs make them very difficult to characterise and develop. In addition, the location of a producer within the fracture network also control flow rates and affect the pressure response; however, conventional well-test analysis assumes that the producer is located in symmetrical fracture networks. To improve our understanding of fracture flow behaviour from well-test data, and in order to better characterise the impact of fractures on reservoir performance, we investigate the effect of variations in fracture conductivity and location of the producer in the fracture network on the pressure transient responses.
Naturally fractured reservoirs (NFR) with well-connected fracture networks are traditionally simulated using the Dual-Porosity (DP) model. However, several studies have shown that the classic DP response (V-shape) corresponding to the DP model is an exceptional behaviour applicable only to certain reservoir geology and does not apply to all NFR. To overcome the limitations of the characteristic flow behaviour inherent to this model, we employ Discrete Fracture Matrix (DFM) modelling technique and an unstructured-grid reservoir simulator to generate synthetic pressure transients in all fracture networks that we analysed. Our rigorous and systematic geoengineering workflow enables us to correlate the pressure transients to the known geological features of the simulated reservoir model.
We observed that depending on the location of the producer in the fracture network and the properties of the fractures that the producer intercepts, the synthetic pressure transients vary significantly. We therefore use these insights to quantify the impact of variation in fracture conductivity and producer location on fracture flow behaviour and systematically present interpretations to these behaviours. Our findings enable us to interpret some unconventional features of intersecting fractures with variable conductivity. We observed that the behaviour of two intersecting fractures where the well asymmetrically intercepts a finite-conductivity fracture can be similar to that of a well intercepting a fracture in a connected fracture network with uniform fracture conductivity. Furthermore, a well intercepting a finite-conductivity fracture in NFR with both finite- and infinite-conductivity fractures would yield a dual-porosity response that may otherwise be absent if the fracture network is assumed to have uniform conductivity.
This paper presents the results of an experimental study on the effects of various CO2-injection modes on immiscible flooding performance in heterogeneous sandstone porous media.
Core flooding experiments were conducted for
Reservoir heterogeneity plays a critical role in determining the successes of the EOR processes, but its effect has rarely been comprehensively quantified in the laboratory. The limited experimental studies conducted to date seem to suffer from a number of deficiency mainly associated with sample preparation and experimental setup. In the present work, in addition to investigating a number of factors rarely studied experimentally before (e.g. effect of crossflow), attempts have been made to overcome the deficiencies of previous studies. Thus the results of this study can be insightful in overcoming the current challenges in capturing the importance of geological uncertainties in the current and future EOR projects.
Chen, Wenbin (China University of Petroleum) | Jiang, Hanqiao (China University of Petroleum) | Li, Junjian (China University of Petroleum) | Jiang, Shan (PetroChina Research Institute of Petroleum Exploration & Development) | Yang, Hanxu (China University of Petroleum) | Qiao, Yan (China University of Petroleum)
The karst caves and fractures are widely developed in carbonate reservoirs, which results in strong spatial heterogeneity. So the parameters obtained from its cores and numerical simulation are limited to reflect its production situation of the entire reservoir, which causes that the traditional economic prediction method for carbonate reservoirs has a high risk. To solve these problems, this paper proposes a new method to accomplish the economic prediction based on expert library and oilfield database, named Delphi-AHP-TOPSIS-MLS-FNPV complex algorithm (DATMF). DATMF method can take account of geological factors, such as sedimentary facies, reservoir types, the characteristics and heterogeneity of caves and fractures. It also considered the impact of production factors on the economic prediction, such as oil production, annual decline rate of production, well spacing density. The process of the DATMF method is as follows: First, establishing a set of hierarchical structure to describe the carbonate reservoirs in the database; Secondly, optimizing the database and analyzing the data based on the expert library; Thirdly, predicting the key development parameters of the new reservoir according to its geological data; Finally, substituting these parameters into the future net present value (FNPV) method to complete the economic prediction of the new carbonate reservoir. Through the calculation example of T7-444CH reservoir, it is found that DATMF method can predict oil production, investment recovery period, and the future net present value, etc. quickly and accurately. On the one hand, it greatly reduces the time and money cost of using traditional economic prediction methods. On the other hand, comparing with the popular big data analysis method, it improves the data's quality and increases the result's professionalism and practicality by using experts’ experience to constraint data, which makes the DATMF method can work on the smaller database. It is very suitable for the DATMF method to be applied in the early or middle stage of oilfield information construction.
Inconsistent production performance from wells completed in similar pay zones has been observed when shale formations are exploited through horizontal wells. Ineffective completion practices, fracture design, and reservoir heterogeneity have generally been blamed for the variability in the performance. Limited importance has been attached to drilling quality and well trajectory placement in the current approaches by the operators. The objective of this study is to demonstrate an engineered lateral landing approach for improved long-term productivity in the unconventional reservoirs.
Coupling the reservoir model to the wellbore and accounting for the transient flow behavior are important for improving deliverability in horizontal wells. The study in this paper encompasses a field case study of a geocellular and geomechanical earth model in the Permian basin, which involves hydraulic fracturing modeling, reservoir simulation, fluid flowback, and transient wellbore flow modeling. Pressure losses accounted for in the reservoir, in the near-wellbore region, and in the wellbore profile are modeled and calibrated with bottomhole and surface gauge measurements. Complex hydraulic fracture geometry and numerical reservoir simulation are used to characterize the pressure losses in the reservoir. Transient wellbore fluid flow considerations are used to evaluate the pressure losses in the wellbore.
Based on the fracturing fluid type, the conductivity profile of the hydraulic fractures, connection to the wellbore, and coverage of the pay zone are important criteria in considering the landing location for wells in unconventional reservoirs. However, having the most effective hydraulic fracture design is not enough to decide the well trajectory. Mitigating liquid loading, fluid flowback, proppant settling, and cross-flow of reservoir fluid helps to diagnose the true production potential. Therefore, transient flow models were coupled to the reservoir and fracture models to design a more-effective well trajectory.
The study demonstrates the need to couple the wellbore model to the reservoir simulation and hydraulic fracturing model in shale formations to optimize well landing, trajectory profile, and long-term productivity.
The methodology provides the first integrated data workflow for well drilling and trajectory planning in unconventional reservoirs that is generated from the perspective of reservoir potential and deliverability. Although variances exist in completion effectiveness due to reservoir heterogeneity, applying the robust modeling workflow as discussed in this study would help deliver consistent results that can be used in field management and EUR estimates across various shale basins.
The field development phase prior to investment sanction is characterized by relatively large uncertainties at the time important decisions have to be made. It is, for instance, crucial to select an appropriate recovery strategy (depletion or injection) to obtain optimal hydrocarbon cumulative production whilst ensuring good profitability of the project. Evaluation of reservoir as well as economic uncertainties and quantification of their impact are needed before the field development concept selection.
This paper describes how to stochastically assess reservoir and economic uncertainties and the screening process used to select the best recovery strategy. The chosen methodology is the combination of uncertainty studies, including both continuous, discrete and controllable parameters. The different screened scenarios are combined in a stochastic decision tree, built-up through decision and chance nodes, to establish a distribution of recoverable volumes and rank the recovery strategies given a chosen criterion. A second uncertainty study is performed by adding economic uncertainties to the initial set of reservoir uncertain parameters. Eventually a new decision tree is established and scenarios ranked using economic criteria.
The application of this methodology to an oil field from the Norwegian continental shelf and how recovery strategies are ranked are presented in this paper. The described methodology has exhibited the risks and uncertainties carried by the project, as it was possible to rank the different solutions based on the dispersion of the recoverable volumes distribution and/or on the net present value (NPV). In the context of a marginal or large capex project, a robust P90 case is required and this may therefore influence the choice of the recovery strategy. For instance, a scenario yielding the largest hydrocarbon volume may not be selected because it requires too many wells and/or too large investment if one of these criteria is defined as the most important. In addition, the combination of uncertainty studies enabled a full economic evaluation covering the entire recoverable volumes distribution whereas in many projects economic evaluation is focused on the P90, Mean and P10 scenarios.
The two-step integrated approach allows a decision to be made whilst taking into account both reservoir and economic aspects. Having a combined stochastic approach to the reservoir and economic uncertainties avoids a biased decision. All cases are stochastically covered and screened using a systematic and unified methodology that gives the same weight to each scenario.
Rognmo, Arthur Uno (University of Bergen) | Fredriksen, Sunniva Brudvik (University of Bergen) | Alcorn, Zachary Paul (University of Bergen) | Sharma, Mohan (University of Stavanger) | Føyen, Tore (University of Bergen, SINTEF Industry) | Eide, Øyvind (University of Bergen) | Graue, Arne (University of Bergen) | Fernø, Martin (University of Bergen)
An ongoing CO2-foam upscaling research project aims to advance CO2-foam technology that accelerate and increase oil recovery, with reduced operational costs and carbon footprint during CO2 EOR. Laboratory CO2-foam behavior will be upscaled to pilot scale in two onshore carbonate and sandstone reservoirs in Texas, USA. Important CO2-foam properties such as local foam generation, bubble texture, apparent viscosity and shear-thinning behavior with a nonionic surfactant were evaluated using Pore-to-Core upscaling to develop accurate numerical tools for field pilot prediction of increased sweep efficiency and CO2 utilization. On pore-scale, silicon-wafer micromodels showed in-situ foam generation and stable liquid films over time during static conditions. Intra-pore foam bubbles corroborated apparent foam viscosities measured at core-scale. CO2-foam apparent viscosity was measured at different rates (foam rate scans) and different gas fractions (foam quality scans) at core-scale. The highest mobility reduction (foam apparent viscosity) was observed between 0.60-0.70 gas fraction. The maximum foam apparent viscosity was 44.3 (±0.5) mPas, 600 times higher than that of pure CO2. The maximum apparent viscosity for the baseline (reference case, without surfactant) was 1.7 (±0.6) mPas, measured at identical conditions. CO2-foam showed shear-thinning behavior with approximately 50% reduction in apparent viscosity when the superficial velocity was increased from 1 ft/day to 8 ft/day.
Sedimentary methane hydrates contain a vast amount of untapped natural gas that can be produced through pressure depletion. Several field pilots have proven the concept with days to weeks of operation, but the longer-term response remains uncertain. This paper investigates parameters affecting the rate of gas recovery from methane hydrate-bearing sediments. The recovery of methane gas from hydrate dissociation through pressure depletion at constant pressure was studied at different initial hydrate saturations in cylindrical sandstone cores. Core-scale dissociation patterns were mapped with magnetic resonance imaging (MRI) and pore-scale dissociation events were visualized in a high-pressure micromodel. Key findings from the gas production rate analysis are: 1) The maximum rate of recovery is only to a small extent affected by the magnitude of the pressure reduction below the dissociation pressure. 2) The hydrate saturation directly impacts the rate of recovery, where intermediate hydrate saturations (0.30 – 0.50) give the highest initial recovery rate. These results are of interest to anyone who evaluates the production performance of sedimentary hydrate accumulations and demonstrate how important accurate saturation estimates are to predict both the initial rate of gas recovery and the ultimate recovery efficiency.
Polymer injection might lead to incremental oil recovery and increase the value of an asset. Several steps have to be taken to mature a polymer injection project. The field needs to be screened for applicability of polymer injection, laboratory experiments have to be performed, and a pilot project might be required prior to field implementation.
The decision to perform a pilot project can be based on a Value of Information (VoI) calculation. The VoI can be derived by performing a workflow capturing the impact of the range of geological scenarios as well as dynamic and polymer parameters on incremental Net Present Value (NPV). The result of the workflow is a Cumulative Distribution Function (CDF) of NPV linked to prior distributions of model parameters and potential observables from the polymer injection pilot.
The impact of various parameters on the CDF of the field-wide NPV can be analyzed and in turn used to decide on what measurements from the pilot have a strong sensitivity on the NPV CDF and are thus informative. In the case shown here, the water cut reduction in the pilot area has a strong impact on the NPV CDF of the polymer injection field implementation. To extract maximum information, the response of the pilot for water cut reduction needs to be optimized under uncertainty.
To calculate the VoI, the Expected Monetary Value (EMV) difference of a decision tree with and without the pilot can be used if the Decision Maker (DM) is risk neutral. However, if the DM requires hurdle values through a Probability of Economic Success (PES), Value Functions (VF) and Decision Weights according to the Prospect Theory should be used. Applying risk hurdles requires a consistent use of VFs and Decision Weights for calculating VoI and the Probability of Maturation (POM) of projects.
Modeling acid fracturing operations in carbonate formations is performed to evaluate the possible improvement in well productivity. Models are developed to mainly estimate the acid penetration length and the fracture surfaces etched-width profile. Variable combinations of these two parameters produce a significant difference in the fracture productivity. To better estimate these parameters, a reliable fracture propagation model should be coupled with the acid reaction/transport model. Simulating weak acids or dolomite formations reactivity requires the inclusion of a heat transfer model. The model provided in this study couples these factors as fractures propagate to finally obtain the fracture conductivity distribution along its length.
The fracture propagation model continuously updates the domain for the acid model. A transient acid convection and diffusion equation is solved and the fracture etched-width profile is calculated. An iterative procedure is implemented in a temperature dependent kinetic model which is stopped when both the temperature and acid solutions converge. When injection stops, acid etching and the fluids temperature are updated as the fracture closes. As the final etching profile is drawn, conductivity is calculated using a correlation that considers formation heterogeneity.
Coupling fracture propagation shows a significant difference on the acid model solutions compared to that assuming constant fracture geometry. For extremely high Peclet number that represents a very retarded acid system, a constant drop in the etched-width value until reaching zero at the fracture tip is theoretically obtainable. For lower Peclet numbers, the etching profile is shown to be sharply declining towards the fracture end. This is in contrast with the non-coupled approach from which a uniform etching profile is obtained at moderate to high Peclet numbers. It is also observed that the simulation of acid injection in non-coupled, constant fracture geometry always overestimates the acid penetration distance. The etched-width distribution and the acid penetration length are temperature sensitive, especially in dolomite formations. Temperature coupling shows that the maximum etching in dolomite formations occurs away from the fracture entrance as acid reactivity increases. It also shows that the cooling effects of the first stage pad fluid on improving the acid penetration distance is limited.
Simulating acid fracturing operations assuming constant final fracture geometry and an average single temperature is time efficient but results in inaccurate solution. This paper quantifies the effects of integrating fracture propagating and heat transfer models on the acid etching pattern from which, a better estimate of the fracture productivity is expected.
Much work has been done targeting hydrocarbon fluids in organic materials of source rocks such as kerogen and bitumen. These were, however, limited in scope to simple fluids confined in nanopores and ignored multi-component effects. Recent studies using hydrocarbon mixtures revealed that compositional variation caused by selective adsorption and nano-confinement significantly alters the fluids phase equilibrium properties. One important consequence of this behavior is capillary condensation and trapping of hydrocarbons in nanopores. Fluid expansion is not an effective mechanism in these pores. To show the impact of lean gas injection on the hydrocarbons recovery, an investigation is carried out using equilibrium molecular simulations of hydrocarbon mixtures with varying concentrations of CO2. The results with N2 are also presented for comparison. We show that large molecules in the mixture are left behind in nanopores are generally responsible for the residual hydrocarbon amount, and that high-pressure CO2 injection extracts more hydrocarbons from the nanopores than that based on pressure depletion only. In these small pores, the injection pressure and the kind of injected gas play a critical role in recovery. We also show that the nanopore surface area, rather than the nanopore size, is the primary factor affecting the residual amount. CO2 molecules introduced into the nanpores during the soaking period of a cyclic injection operation lead to exchange of molecules and a shift in the phase equilibrium properties of the confined fluids. This exchange has a stripping effect and in turn enhances the hydrocarbons recovery. However, the subsequent production and pressure depletion has no additional impact on the recovery beyond the stripping effect. CO2 injection and soaking has the ability to extract the heavier hydrocarbon fluids irrespective of the operating pressure conditions, while the pressure depletion produces the lighter fluids from the nanopores.