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.
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.
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.
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
In petroleum industry, uncertainty analysis is frequently used to define the expected probabilistic range of oil, gas and water production profiles. This paper describes a new application, aiming to estimate the probabilistic concentration range of hydrogen sulphide (H2S) in produced fluids. Several oilfields undergo increasing concentrations of produced H2S, typically during seawater injection for secondary recovery. Usually, such toxic and corrosive compound is generated by Sulphate- Reducing Bacteria (SRB). Bacterial activity is not favoured in the reservoir original environment, but can become feasible after water injection, mainly because injected water can have high sulphate contents, can cool certain regions of the reservoir, and can dilute bacterial inhibitory compounds in formation water.
Reservoir souring modelling is useful to anticipate decisions, either by preventive measures or a mitigation strategy, to avoid exposition of people, environment and installations to serious hazards. Inasmuch there are significant uncertainties in various simulation parameters, H2S concentrations presented as a probabilistic range - instead of a deterministic value - can be worthy to fine-tune the acceptable level of risk tolerance in the decision-making process.
Each field development scenario relates to a specific sensitivity to the simulation variables and probabilistic ranges are, in some cases, very wide. Commonly, not only microbial-related parameters are relevant: part of the biogenerated H2S is retained in the reservoir, due both to adsorption/reaction with rock minerals and to partition of H2S in water and oil phases.
Since 2005, the mentioned probabilistic approach is used in Petrobras to base decisions that have a large impact on the field development overall costs.
Intermittent alkali flooding can significantly enhance oil recovery in oil-wet carbonate reservoirs. The method basically acts in two ways, by reducing the interfacial tension between the reservoir fluids and by reversing the wettability to a more favorable condition. However, the reversal of wettability requires aging time to reach the equilibrium. An intermittent or a pausing period is then adopted for the proposed alkali flooding process to let the surface reaching the maximum favorable wettability.
As the injected fluid is paused during the flood process, vertical or inclined reservoirs are more suitable for this combination because the water tongue effect does not cause an early breakthrough. Laboratory results show that one-week-intermittent alkali flooding in homogeneous carbonate rock yields greater oil recovery, about 10 percent larger than conventional continuous alkali flooding in a proper range of injected alkali concentration. Low alkali concentration causes quick alkali depletion as time increases, while high alkali concentration causes pore plugging by in-situ precipitation of insoluble soap. The alkalinity of injected fluid should be kept as high as possible. Therefore, a strong alkali such as sodium hydroxide is recommended. High acid concentration in crude drives in-situ saponification frontward; hence, alkali concentration range should be carefully studied. Normally, high initial water saturation prevents the system from alkali accumulation and, as a consequence, insoluble soap precipitation is less concerned. Fractured carbonate reservoirs are probably the most suitable candidates for the application of this technique, since aging time would allow alkali to diffuse to, and reverse the wettability of the inaccessible and unswept zones. The proposed technique seems very effective to increase the ultimate oil recovery in oilwet carbonate reservoir. The drawbacks seem acceptable and the expected results are promising.
Ogunyemi, Taofeek (Schlumberger North Africa) | Montaggioni, Philippe Jean (Schlumberger) | Azzouguen, Atmane (Schlumberger) | Kourta, Mourad (Shlumberger North Africa) | Kodja, Said (Sonatrach Inc.) | Madani, Messaoud (Sonatrach Inc.)
The economical viability of the Cambrian sandstone reservoirs in the Hassi Messaoud field is closely linked to the presence of fractures. Natural or hydraulically induced fractures control hydrocarbon productivity due to the low porosity, low matrix permeability and heterogeneous sedimentological characteristics of these fluvial deposits.
Fracture corridors and permeable fault zones also represent a major risk of water breakthrough from the underlying aquifer in horizontal wells. The identification and characterization of open fractures and conductive faults is of critical importance for the completion decisions in this field.
Whole cores enable a comprehensive description of fractures (morphology and type) over the cored sections of the reservoir. Meso-scale fractures can also be identified, oriented and characterized (open vs. cemented) on high resolution borehole images over the entire open-hole section. When combined with pressure transient analyses and production data, borehole image logs provide invaluable information on the enhanced fracture conductivity, the completion optimization and the reservoir management for sustaining long term production in these complex reservoirs.
Wells with high fracture density usually correlate with high production rates as long as the dominant fracture strike is close to the direction of the maximum in-situ horizontal stress (sH). Wells with low fracture density or dominant fracture strike oriented oblique or perpendicular to sH generally show poor production rates.
This paper discusses case studies of fracture and fault characterization from a combination of borehole images with production and pressure transient data to provide an explanation for ambiguous production observations and well test data. Examples of completion optimization utilizing this integrated approach are also presented.
Although it is widely admitted that the presence of fractures (natural and hydraulic) is directly linked to the production of the hydrocarbon trapped in the Cambrian reservoirs of the Hassi Messaoud field, very little is known about the relationship between their properties and spatial distribution with the dynamic measurements of the reservoir. Extensive core analyses have shown that permeability anisotropy at different scales is controlled by the interplay of depositional facies and fracture systems in this field.
The design, execution and economic aspects of hydraulic fracturing to improve well productivity by limiting the effect of permeability anisotropy in the Cambrian reservoirs of Hassi Messaoud field have been studied by many authors. These topics are particularly well documented by Rahmouni et al, (2002) and Guehria et al, (2005).
Similar patterns in production profiles, with high initial production rates followed by a sharp decline, have been observed across the majority of both hydraulically fractured and conventional wells in Hassi Messaoud field. In the majority of the transient test data performed in horizontal wells, the analysis of the pressure derivative reveals that production comes from both natural fractures and layered media in a bilinear flow characterized by a slope of ¼ (m = 0.25) of the Log-Log pressure-derivative plot (Azzouguen et al, 2000).
Recently there has been an increasing interest in simultaneous water-alternating-gas (SWAG) in oil recovery operations. This method involves the simultaneous injection of water at the top of the reservoir formation and injecting gas at the bottom of the formation. The difference in water and gas densities will provide a sweeping mechanism in which water tends to sweep hydrocarbons downward and the gas tends to sweep the hydrocarbons upward. It is expected that the two displacement mechanisms will work on establishing a flood front, which will increase the sweep efficiency and thus the oil recovery. This study investigated the performance of SWAG in oil recovery operations.
A three-dimensional finite-difference black oil reservoir simulator has been used to determine the reservoir management strategies in order to optimize the oil recovery using SWAG injection technique. A specific strategy that was studied includes the use of horizontal injectors in conjunction with vertical producers. This well configuration has been shown to yield the best oil recovery compared to other well configurations. The management strategies involved studying different design parameters to maximize the recovery performance. Such parameters include; mobility ratio between oil and water phases, viscosity ratio between gas and oil phases, location of the water and the gas injectors, and injection rates of water and gas. Results showed the investigated parameters are critical in the success of the proposed injection SWAG scheme. The study provides the conditions under which this SWAG injection technique may yield higher recovery performance.