One of the key features of E&P companies is their proved reserves in hydrocarbon deposits. Reserve estimation requires knowledge of Initial Hydrocarbon in Place, technical reserves and economic conditions including annual cash flow estimation in the forecast period. Since all parameters used in evaluation procedure are burdened by rather more than less certainty. Therefore, in a sophisticated evaluation process, there should be determined not the expected values only (deterministic way), but errors/uncertainty of estimation as well (stochastic way) applying Monte Carlo simulation.
The estimation procedure comprises three main stages (the third stage /economic modeling/ is not discussed in this paper). In the first stage, key input data (e.g., area, thickness, porosity, and so on) are treated as statistical variables, and the result of the simulation is probability distribution function of HCIIP. This is an input of next stage.
n the second stage technical reserves (recoverable resources) should be estimated. There could be several assumptions for production procedure for a reservoir (as e.g., drive mechanism, hydrodynamic system, phase behavior of reservoir fluids, well spacing, water injection, presence of pressure barriers etc). Each regime (i.e. scenario) can be modeled applying input parameters as statistical variables. This method is named a multiscenario method in the literature. Simulation result for each scenario is a probability distribution function (PDF). While, expected value of PDF reconstructs the deterministic result and gives a basis for project evaluation, the "width?? of PDF is proportional with uncertainty of the estimation. Estimating probability of each scenario a combined technical reserve PDF can be derived. Its first percentile can yield proved reserve for booking procedure after economic limit test.
Authors show some case histories how to apply method after a brief theoretical summary referring to SPE-PRMS accepted.
Natural tracers (geochemical and isotopic variations in injected and formation waters) are a mostly unused source of information in reservoir modeling. On the other hand, conventional inter-well tracer tests are an established method to identify flow-patterns. However, they are typically underexploited, and tracer-test evaluations are often performed in a qualitative manner, and rarely compared to simulation results in a systematic manner. To integrate natural and conventional tracer data in a reservoir modeling work-flow, we use the ensemble Kalman Filter (EnKF) that has recently gained popularity as a method for history matching. The EnKF includes online update of parameters and the dynamical states. An ensemble of model representations is used to represent the model uncertainty. In this paper we include conventional water tracers, as well as natural tracers (i.e. geochemical variations), in the EnKF approach. The methodology is demonstrated by estimating permeability and porosity fields in a synthetic field-case, based on a real North Sea field-example. The results show that conventional tracers and geochemical variations yield additional improvement in the estimates, and that the EnKF approach is well suited as a tool to include this information. The principal benefit from the methodology is improved models and forecasts from reservoir simulations, through optimal use of conventional and natural tracers. Some of the natural tracer data, scale forming ions and toxic compounds, e.g., are monitored for other purposes and exploiting such data can yield significant reservoir model improvement at a small cost.
Modeling of supercritical CO2 injection into a deep saline aquifer from a carbonate formation (calcite and dolomite, with minor anhydrite) was performed using TOUGHREACT (Xu et al. 2006) with Pitzer ion-interaction model implementation for handling high salinity problems (Zhang et al. 2006). The formation brine salinity is ~225,000 ppm (NaCl dominant), temperature at 102oC and pressure at 225 bars. CO2 injection rate was considered constant for a period of 1 year through a horizontal well in a 3D model domain. The carbonate formation was assumed to have homogeneous porosity and permeability and to be overlaid by an impermeable seal. The effect of a higher permeability fault with orientation perpendicular to the horizontal well, and bounded by the impermeable overburden, was evaluated. The impact on mineralogical and rock property changes in the saline aquifer during injection has been assessed. The simulations found that: (1) the higher permeability fault acts as a CO2 conduit; (2) a dryout zone is developed within a few meters from the injection well due to displacement by supercritical CO2 and dissolution of water into CO2 stream (3) at the front of the dryout zone, brine is further concentrated due to water dissolution into CO2, pH is lowered from 5.5 to 3.1, halite (NaCl) and anhydrite (CaSO4) precipitate, and the brine becomes CaCl2-dominant; (4) near well-bore porosity reduces by ~5%-17% due to halite precipitation (dryout zone); (5) HCl gas is generated from the dryout front; (6) calcite and dolomite dissolve as the CO2 plume advances during injection; (7) anhydrite, however, slightly dissolves along the CO2 front, but precipitates in the area corresponding to the CO2 plume with higher proportions near well-bore. These findings are valuable for the assessment of injectivity changes and near well-bore stability of saline aquifers in carbonate formations during injection of CO2. The overall mineral trapping in hundreds of years is not the focuss of this paper. However, from ongoing modeling experiments, mineral trapping is anticipated to be not significant for the mineralogies and brine chemistries and salinities of the carbonate formation under assessment. This study method is useful for the further evaluation of engineering options to enhance immobile trapping of CO2 and mitigation measures for potential injectivity impairment.
CO2 injection is increasingly considered as having potential applications as a possible enhanced oil recovery (EOR) process for oil reservoirs. However, poor sweep efficiency has been a problem in many CO2 floods and hence, the injection strategies like WAG (water-alternating-gas) injection have been proposed and applied in the field as a way to mitigate the problem. An alternative injection strategy is CO2-enriched (carbonated) water injection (CWI).
This paper presents the results of an integrated experimental and theoretical study on the application of CO2-enriched water flooding for enhanced oil recovery. Direct flow visualisation experiments were carried out using high-pressure transparent porous media. The results of our visualisation experiments demonstrate that CWI, compared to unadulterated water injection, improves oil recovery. The additional oil is recovered as a result of an improved sweep efficiency, due to the oil swelling, viscosity reduction and coalescence of the isolated oil ganglia as a result of CO2 diffusion. This injection strategy is particularly attractive in waterflooded oil reservoirs in which high water saturation adversely affects the performance of conventional CO2 injection methods. CWI can also be carried out in combination with reservoir depressurisation carried out subsequent to CWI or in a cyclic manner in which carbonated and plain water cycles are injected in succession.
The results of a mathematical model are also presented which honours our experimental observations and simulates the dynamic process of oil swelling and shrinkage due to CO2 transfer during Carbonated water and plain water injection.
When planning oil and gas wells, the cost and duration uncertainty, related to the well construction process, could be a big concern.
Traditionally, Drilling Engineers, in different geographical areas, have utilized different estimation methods with a consequent difficulty of communication. This tool could represent a common platform on the well construction cost and duration estimation.
In recent years probabilistic well cost estimates have become a requirement as part of the internal procedures of the E&P Companies, e.g. when applying for an Authorization for Expenditure (AFE) approval.
This paper describes the tool and methodology which have been developed upon request by Eni E&P to introduce and strengthen the application of probabilistic well construction cost and duration estimation within the drilling department. The tool offers decision support for well and operation planning and has the potential to make the cost and duration uncertainty analysis an integrated activity of the well planning process.
The software is characterized by a user friendly interface and is tailored to Drilling Engineers' needs, to easily and effectively perform the probabilistic risk analysis and to systematize the corresponding workflow.
It also facilitates both internal and external communication, since it has the potential to be used as a standard tool.
In conclusion, the developed tool allows Drilling Engineers to:
• perform a quantitative risk analysis;
• calculate risked cost and duration;
• identify operations which mostly affect drilling uncertainties;
• evaluate and select alternative technical solutions;
• prepare prevention and mitigation plans for the reduction of both duration and cost.
Ligthelm, Dick Jacob (Shell Intl. E&P BV) | Gronsveld, Jan (Shell Intl. E&P BV) | Hofman, Jan (Shell Intl. E&P BV) | Brussee, Niels (Shell Intl. E&P BV) | Marcelis, Fons (Shell International Exploration and Production B.V.) | van der Linde, Hilbert (Shell Intl. E&P BV)
As brine composition profoundly influences reservoir wettability and hence microscopic sweep, careful design of injection brine is part of a strategy to improve on oil production in existing and future water flooding projects, in both sandstone and carbonate reservoirs and in combination with follow-up EOR projects.
The following results were found: (1) Formation water with higher salinity level correlates to a higher content of multivalent cations. This causes the (sandstone) reservoir wettability to be more oilwet; (2) The field-observed temporary reduction in watercut during breakthrough of so-called "Designer Waterflood?? water in a Middle Eastern sandstone reservoir with highly saline formation water was interpreted to be caused by an oil bank ahead of the slug of injected water; (3) The oil bank results from improved sweep by wettability modification to more waterwet state. The interpretation was confirmed by laboratory experiments; (4) Experiments in limestone core plugs demonstrate similar wettability modification, if the sulphate ion content in the invading brine is far in excess of the calcium ion content.
Based on these results the following conclusions were drawn: (1) Designer Waterflooding may increase the Ultimate Recovery of oil by at least a few percent; (2) There is scope for further improvement in oil production by flood front stabilization by adding low concentration polymer to the optimised slug; (3) If future EOR projects are planned, a Designer Waterflooding pre-flush is recommended to obtain more favourable oil desaturation profiles and savings on polymer costs; (4) In case of seawater injection into reservoirs with formation water of low salinity level, removal of multivalent cations from the seawater should be considered to avoid the potential risk that the reservoir becomes more oilwet, which will result in reduced sweep.
A study was carried out to determine the geomechanical effects of polymer flooding in an unconsolidated sand reservoir. The work involved laboratory-scale polymer injections in unconsolidated sand blocks to identify the injectivity mechanisms, numerical analyses for fracture prediction, and geomechanical modeling of the formation to examine the potential of shear failure and containment loss during flooding.
Laboratory tests under polyaxial conditions indicate that near-wellbore fracturing and permeability increase in unconsolidated sands occurs at net injection pressures limited to 2.0 MPa. These findings were applied to fracture modeling. Geomechanical modeling suggests large-scale shear failure in the sand and in the bounding shale during polymer flooding. These are expected to affect both the fracture containment and the vertical-hole integrity. Finally, fracture predictions underscore the importance of the geomechanical considerations on determining the fracture dimensions and containment. Sensitivity analyses also point to the significance of bounding several key parameters for fracture prediction. These include sand-shale stress contrast, fluid quality and TSS content, fluid rheology and effective viscosity in the formation, and the filtercake properties in the presence of polymer.
This paper is intended to provide a geomechanical perspective on the generally complex problem of polymer flooding in unconsolidated formations containing viscous oil. The work also offers some insights into the critical issues that must be examined in such situations to avoid catastrophic failures, and highlights the existing technological gaps in the current predictive capabilities.
The model of Stone for gravity segregation in gas improved oil recovery (IOR) indicates the distance injected gas and water travel together before complete segregation. This model is very useful for co-injection of water and gas into horizontal depleted reservoirs. A proof by Rossen and van Duijn showed that the model of Stone applies to steady-state gas-liquid flow, and also foam flow, in horizontal reservoirs as long as the standard assumptions of fractional flow theory (incompressible flow, Newtonian mobilities, local equilibrium) apply. However, until now, there is no study on application of this model for tilted reservoirs. In this paper, by using a three dimensional finite-difference compositional reservoir simulator, we investigate gravity segregation in tilted reservoirs and then compare the results with the model of Stone. This study shows that the math proof by Rossen and van Duijn provided for the horizontal reservoir doesn't work if the reservoir is tilted, and that the model of Stone should be corrected to apply in tilted reservoirs. There are good agreements between the corrected model and the reservoir simulator results in tilted reservoirs.
Renewable energy sources, such as wind energy, are expected to be sources of sustainable energy as fossil fuels are depleted. Wind energy is a promising, but intermittent energy source. Large scale energy storage such as Compressed Air Energy Storage (CAES) is needed to account for intermittency. CAES is designed to store off-peak energy to make it available for use during peak demand periods. Currently, CAES plants are located in caverns, which are uncommon in occurrence. CAES wind farms can become a more reliable energy source if other geological structures such as depleted hydrocarbon reservoirs are used for storage.
This study used a black oil simulator to model CAES in a typical cavern setting, in a hypothetical reservoir setting, and in a potential CAES wind farm area in the Greater Green River Basin (GGRB) of Wyoming. The cavern setting is modeled after the Huntorf CAES facility in Germany. Wind speed and resulting power data for GGRB models were taken from the Medicine Bow Wind Project in Wyoming. Porosity, permeability, and injectivity information from GGRB was used to construct four models of hybrid systems that combined wind energy and CAES for different geographical locations and geological properties.
The model of a cavern setting validated use of a black oil simulator for CAES applications. The study showed that CAES can be used in a variety of geologic settings, and that the GGRB has good potential for supporting wind energy and CAES systems. This talk will present details of the study and provide suggestions for future work.
*Now with Schlumberger
**Now with Chevron
High potential of tight sands (quartzitic sandstones) makes these non-conventional reservoirs a priority for oil companies during next decades. Due to numerous formation evaluation challenges in tight sands, conventional logging does not allow reliable and comprehensive investigations that are essential for exploration and development.
Classical logging techniques/measurements are frequently affected by significant uncertainties, leading sometimes to erroneous evaluation results.
New technology has brought advanced logging methods improving accuracy and reducing uncertainties of reservoir evaluation and characterization. Efficient implementation of these techniques is explained considering resolution/precision and limitations of measurement physics.
Best practices for logging in this type of formation are recommended with guide-lines and examples. Depending on well category (exploration, semi-exploration, appraisal or development), appropriate and optimum logging programs can be designed and sequentially performed to acquire full set of necessary data/information.
Latest generation of logging tools, in sonic, nuclear magnetic resonance, accelerator-neutron, formation-tester and analysis-sampling techniques, which offer significantly better evaluation, are proposed in integrated and optimized methodology. All of advanced logging tools may not be needed systematically for all types of wells; selective criteria are analyzed according to defined objectives/needs, reservoir particularities or/and sequential investigation results.
Data/information provided by tool answers-measurements are linked to key equations that will be accurately solved in different workflow implemented within the framework of formation evaluation, reserves estimation, completion selection, stimulation design and enhanced production projects.
This approach could be considered as guide lines for preparation of specific tool combinations and adequate logging programs fundamental for tight sands potential assessment and important management decisions.
Introduction and challenges
Tight sands reservoirs are generally defined as quartzitic sandstones with matrix intergranular porosities in the range of 4 - 8% and permeabilities less than 1 md, with expected value of average effective gas permeability less than 0.6 md. (Reference: German Society of Petroleum and Coal Science and Technology).
With their large volume and long-term potential, these formations are strategic reserves and main objective for hydrocarbons production maintain and increase in numerous regions (e.g.: North Africa). However evaluation and characterization of these reservoirs are problematic due to their complexity and limitations of different investigation and measurement techniques.
These formations are stemming from heterogeneous and discontinued sedimentary layers/units affected by spatial-variable diagenesis transforms (physics-chemical) and multiple tectonic stresses that caused anisotropy important and changes in their petrophysics properties. Pore volume/morphology change is dominated by extensive diagenesis which leads to an important reduction of intergranular matrix porosity.
Porosity estimation from conventional methods (Neutron-Density-Sonic) is affected by large uncertainties linked to very small volume of fluids and matrix parameters.
Borehole conditions of wells are frequently difficult with induced rugosity and directional failures (break-outs) due to fractures/fissures and important stresses regime.
Very low matrix permeability and heterogeneity makes difficult reservoir pressure estimation and determination of fluid gradients. Supercharging and/or loss of seal during formation pre-tests due to rugosity of stressed/damaged borehole surfaces, is an obstacle for reliable pressure measurements while using conventional formation testers methods; therefore fluids identification and contacts detection are complicated processes.