The giant Chicontepec field contains oil from 18 to 45 oAPI in laminated sandstones of 0.1 to 10 mD at a depth of around 2500 meters (8202 ft). Original Oil in Place (OOIP) is estimated to be 140, 900 MMSTB. The complex geology (complicated structural and stratigraphic nature of the reservoirs), lack of reservoir information and lack of technology availability caused a gap between discovery and development. Throughout a period of several decades some exploration wells were drilled based on 2D seismic and log correlations of the reservoirs.
The exploitation of the Paleonchannel was postponed because most of the wells showed poor productivity. The reasons for the low recovery (around 3%) have never been thoroughly understood. Various hypotheses have been proposed to explain the deficient performance such as partial closing of the fractures with declining reservoir pressure (bubble-point pressure is near initial pressure), inadequate comprehension of the geological model, deficiency in the fracturing technology, oil-wetted or intermediate-wetted reservoirs, applicability of unconventional wells (horizontal wells, casing drilling technology), etc. Today, the Chicontepec Paleochannel is an intermediate stage.
Due to the experience of different fields with similar characteristics, this paper describes an analysis of alternatives that may be considered to resolve the problems of exploitation at the Chicontepec field. Advanced technologies, hydraulic fractures, artificial lift systems, all of them combined with secondary and enhanced oil recovery, may be feasible to sustain or increase production. A number of hurdles will have to be overcome. This field, the second most important oil field in Mexico, should take advantage of the experience learned from these analogous reservoirs.
Geographically, it is located in east-central Mexico in parts of the states of Veracruz, Puebla and Hidalgo. Chincontepec system was deposited under complex tectono-stratigraphic conditions. Geologically, it covers an area of 957,534 acres (Figure 1). Aproximately half of Chicontepec consists of shales or silty shales with the rest of the formation made up of multiple thin sandstones beds and zones of sandstones beds. Typically, between 8 and 16 major reservoirs are present. These set of reservoirs is composed of channel complexes that are flanked by, and rest on, lobe sandstones that grade into distal fan and basin floor deposits, resulting in high heterogeneity. Throughout a period of several decades some exploration wells were drilled based on 2D seismic and log correlations of the reservoirs. The 3D seismic allowed the identification of sand bodies with viable pay thickness. Some wells produce small amounts of water, in general, water-oil contacts have not been identified. X-ray diffraction analysis showed that the clay cointains dominantly kaolinite with a content of 1 to 5 %. The sandstones are immature litharenites consisting of quartz grains, abundant carbonate fragments, and granitic fragments. Because of the abundance of carbonate in the system, the sediments are highly cemented by ferroan calcite and ferroan dolomite, in addition to quartz overgrowths. Core analyses show that the reservoirs are characterized by both low porosity and low permeability, Figure 2. All the reservoirs have permeabilities of 0.1 to 10 mD and porosities ranging from 5 to 15 %. The effective permeability, as determined from build up, fall off, drawdown and step rate test or advance decline analysis, varies from 0.01 to 15 mD.
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.
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.
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.
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.
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.
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
Steam-Assisted Gravity Drainage (SAGD) is a widely used in situ recovery process for heavy oil and bitumen reservoirs. The performance of the SAGD process is tied with growth of the steam chamber which in turn depends on uniform steam delivery along well length and the underlying geology and fluid properties in the near wellbore region. If the reservoir has poor injectivity due to poor underlying geology oil production suffers. This can be avoided in by examining the interwell subcool. The subcool is the temperature difference between the injected steam and produced fluids. In this study, Proportional-Integral-Derivative (PID) feedback control has been employed to control inflow control valves settings to promote subcool to a target value. This control strategy is examined by using a PID algorithm to control SAGD in a detailed three-dimensional heterogeneous reservoir model with properties typical of an Athabasca bitumen reservoir. Specifically, the SAGD injector is divided into six intervals each with its own steam injection pressure. The interwell subcool is calculated and the PID feedback control algorithm is used to direct the subcool to a target value by changing the steam injection pressure in each well interval. The results show that this control method can be used to enhance uniform steam chamber growth and ultimately more oil production with less steam injection. The key benefit of dynamic well control is that the injection strategy is adjusted dynamically to fit the underlying geological and fluid compositional heterogeneity to obtain improved steam conformance along the wellpair. This implies that potentially a priori detailed knowledge of the geological and fluid compositional heterogeneity may not be as critical for well placement for uniform steam conformance.
There are two main objectives of a thermal recovery process for heavy oil and bitumen reservoirs: first, mobilize the oil - this is often done by using high pressure steam, and second, move the mobilized oil to a production well. If one of these two objectives is not met, then the recovery process will not be technically successful. For a steam-based thermal recovery process, the first objective equates to delivering the latent heat of the steam to the oil phase in the oil sand. In general, the more efficient the heat transfer from steam to oil, the more productive and economic is the recovery process. Thus, a key goal of a steam-based recovery process is to control energy delivery within the reservoir. However, thermal production from heavy oil and bitumen reservoirs is difficult because subsurface processes such as steam flow and heat transfer in a system with both geological and fluid compositional heterogeneity tend to be difficult to control. For example, in steam-based recovery technologies such as Steam-Assisted Gravity Drainage (SAGD), displayed in cross-section in Figure 1, the steam chamber that develops in the reservoir may not be uniform along the length of the wells. For example, Figure 2 displays interpreted seismic data of the heated zones in Clearwater bitumen reservoir at the end of the steam injection period in the first three cycles of horizontal well CSS (Imperial Oil, 2006). The images reveal that steam injection is not uniform along the length of the wells. Thermocouple data also reveal that heat transfer in the reservoir is non-uniform and is controlled by the heterogeneity of the underlying geology and fluid composition (ConocoPhillips, 2008). This implies that despite the desire for uniform steam delivery within the reservoir, this is most likely not achieved in the majority of steam injection wells. Recently, an analysis by Zhang et al. (2005) of 4D and crosswell seismic and production data have shown that steam chamber growth and oil recovery are strongly influenced by reservoir geology. Steam chamber growth is especially affected by the presence of low permeability facies in the vicinity of the SAGD wellpair. Furthermore, Gotawala and Gates (2009) have demonstrated that there is a direct link between permeability heterogeneity and the evolution of a SAGD steam chamber.