Maleki, Masoud (Uuniversity of Campinas UNICAMP) | Danaei, Shahram (Uuniversity of Campinas UNICAMP) | Davolio, Alessandra (Uuniversity of Campinas UNICAMP) | José Schiozer, Denis (Uuniversity of Campinas UNICAMP)
Permanent Reservoir Monitoring (PRM) in systems deep-water settings provide on-demand snapshots for hydrocarbon reservoirs at different times during their production history. Delays in the interpretation turnaround of 4D seismic data reduce some benefits of the PRM. These delays could adversely impact the decision making processes despite obtaining information on demand. Using fast-track approaches in 4D seismic interpretation can provide timely information for reservoir management. This work focuses on a fast-track 4D seismic qualitative interpretation in PRM environment, with the aim of choosing the best seismic amplitude attribute (4D) to use. Different seismic attributes are extracted and the one with high signal-to-noise ratio is selected to carry out the 4D qualitative interpretation. All 4D signals are juxtaposed with well production history data to increase confidence in our interpretation. The selected attribute can be interpreted and used for the foreseeable life of field. This workflow has been developed and applied on post-salt Brazilian offshore field to choose the best seismic attribute to conduct the 4D seismic qualitative interpretation.
While many factors in the reservoir cannot be controlled, there are three controllable factors in field development that make a significant impact. More reservoir contact leads to more oil produced. Controlling sand and water means lower treatment costs, and in-situ reservoir management leads to higher cumulative production. While the underlying technologies have been around for up to 20 years, it is only recently that their synergies and true value are understood. This paper will demonstrate the effect each of these technologies has on increasing overall production rates, improving recovery, and reducing the cost per Barrel of Oil Equivalent (BOE).
The successful implementation of multilaterals in the North Sea will be analyzed. Since 1996, over 300 multilateral junctions have been installed on the Norwegian continental shelf fields with currently approximately 30 junctions completed each year.
Additionally, simulations will be used to demonstrate the incremental improvements in oil recovery that can be obtained by using properly designed advanced completions that include multilaterals, sensors, and passive/active flow control equipment.
The paper will evaluate production performance of a vertical well field development base case against scenarios using horizontal and multilateral wells. It will show how fields can be optimized, leading to increased oil and decreased water production.
Production rates can be significantly improved by combining multilaterals with other advanced completion techniques, such as intelligent completions and inflow control devices. The subject field simulation can be further optimized to manage gas and water production.
With a tailored multilateral field design, combined with properly designed advanced completions systems, the simulation succeeds in terms of achieving maximum contact with the oil reservoir and meeting improved ultimate recovery objectives.
It can be concluded that as reservoir contact is increased, a reduced decline in production rate is observed leading to both a higher Estimated Ultimate Recovery (EUR) and optimized drawdown profile distributions. Additionally, results will be presented that have considered oil production and a method to lower production of unwanted fluids or gas.
This paper also demonstrates the value of field development design from the perspective of reservoir simulation. It is through reservoir insight that a level of understanding is created that can help define the optimum well and completion design to meet field expectations.
Advanced multilaterals continue to grow in popularity with many operators, and it therefore becomes important to evaluate the value of different field development methods. This knowledge can aid operators in unlocking new reservoir targets and optimizing field development, and ultimately will improve recovery factors and overall field economics.
Globally, most oil fields are on the decline and further production from these fields is addressed to be practical in cost-effectiveness and oil productivity. Most oil companies are adopting two main technologies to address this: artificial intelligence and enhanced oil recovery (EOR). But the cost of some of these EOR methodologies and their subsequent environmental impact is daunting. Herein, the environmental and economic advantage of microbial enhanced oil recovery (MEOR) makes it the point of interest. Since, there is no need to change much-invested technology and infrastructure, amidst complex geology during MEOR application, it is entrusted that MEOR would be the go-to technology for the sustainability of mature fields.
Despite the benefits of MEOR, the absence of a practical numerical simulator for MEOR halts its economic validation and field applicability. Hence, we address this by performing both core and field- scale simulations of MEOR comparing conventional waterflooding. The field scale is a sector model(fluvial sandstone reservoir with 13,440 active grid cells) of a field in Asia - Pacific.
Here we show that pre-flush inorganic ions (Na+ and Ca2+) affect the mineralization of secondary minerals which influences microbe growth. This further influences carboxylation, which is relevant for oil biodegradation. Also, as per the sensitivity analysis: capillary number, residual oil saturation and relative permeability mainly affect MEOR. Secondary oil recovery assessment showed an incremental 6% OOIP for MEOR comparing conventional water flooding. Also, tertiary MEOR application increased the oil recovery by about 4% OOIP over conventional water flooding. It was established that during tertiary recovery, initiating MEOR after 5years of conventional waterflooding is more advantageous contrasting 10 and 15years. Lastly, per probabilistic estimation, MEOR could sustain already water-flooded wells for a set period, say, a 20% frequency of increasing oil recovery by above 20% for 2 additional years as highlighted in this study.
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A passive tracer that labels gas or water in a well-to-well tracer test must fulfill the following criteria. It must have a very low detection limit, must be stable under reservoir conditions, must follow the phase that is being tagged and have a minimal partitioning into other phases, must have no adsorption to rock material, and must have minimal environmental consequences. The tracers discussed in the following sections have properties that make them suitable for application in well-to-well test in which dilution volumes are large. For small fields in which the requirement with respect to dilution is less important, other tracers can be applied. Figure 1.1 – Production curve of S14CN compared with the production curve of HTO in a dynamic flooding laboratory test (carbonate rock) (after Bjørnstad and Maggio). There are no possibilities for thermal degradation, and it follows the water closely. The 36Cl- is a long-lived nuclide (3 105 years), and the detection method is atomic mass spectroscopy rather than radiation measurements. The disadvantage is that the analysis demands very sophisticated equipment and is relatively time consuming. For mono-valent anions, the retention factors (see Eq. 6.2) are in the range of 0 to -0.03, which means that such tracers pass faster through the reservoir rock than the water itself (represented by HTO). A compound such as 35SO42- may be applied in some very specific cases but should be avoided normally because of absorption. Some anionic tracers may show complex behavior. Radioactive iodine (125I- and 131I-) breaks through before water but has a substantially longer tail than HTO. Both a reversible sorption and ion exclusion seem to play a role here. Cationic tracers are, in general, not applicable; however, experiments have qualified 22Na as an applicable water tracer in highly saline (total dissolved solids concentration seawater salinity) waters. In such waters, the nonradioactive sodium will operate as a molecular carrier for the tracer molecule. Retention factor has been measured in the range of 0.07 (see Eq. 6.2) at reservoir conditions in carbonate rock (chalk). Wood reported the use of 134Cs, 137Cs, 57Co, and 60Co cations as tracers.
To obtain high-quality tracer-response curves that are the basis for the further interpretation, a well-designed sampling program is needed. In general, more samples will give the potential for extraction of more information from field tests. Too often, interpretation is difficult because of limited tracer data. The final objective of a well-to-well study is the interpretation of the response curves. A good analysis of the information given by the tracers, in combination with other available data, gives a better understanding of the flow in the reservoir, not just verification of communication between injector and producer.
Interwell tracer tests are widely used. This article reviews some of the studies reported in open literature. The selection introduces different problems that have been addressed, but the original papers should be studied to obtain a more detailed description of the programs. The Snorre field is a giant oil reservoir (sandstone) in the Norwegian sector of the North Sea. Injection water and gas were monitored with tracers, 18 and the resulting tracer measurements are discussed in this page.
Katiyar, Amit (The Dow Chemical Company) | Patil, Pramod (The Dow Chemical Company) | Rohilla, Neeraj (The Dow Chemical Company) | Rozowski, Peter (The Dow Chemical Company) | Evans, Jay (MD America Energy LLC) | Bozeman, Tim (MD America Energy LLC) | Nguyen, Quoc (The University of Texas at Austin)
An immiscible hydrocarbon foam (HC-Foam) enhanced oil recovery (EOR) pilot has been designed and implemented in a hydraulically fractured tight reservoir in the Woodbine field, Texas. Although gas injection is being considered as the main EOR technology for unconventional tight fractured reservoirs, gaseous foams of this type have not been previously considered as an effective conformance solution. This paper presents experimental evaluation of the surfactant, field pilot design and implementation and performance analysis of the pilot towards developing an unconventional HC-Foam EOR conformance solution. Several surfactants were screened through a bulk foam test for the harsh reservoir conditions (120 ˚C, 3.23% salinity and ~27% clay). The selected surfactant was further evaluated for static adsorption on reservoir rocks at room temperature to ensure an economic field pilot. The surfactant was also evaluated for oil-brine emulsion tendency to mitigate any field implementation issues. A single horizontal injector and two surrounding horizontal producers pad was developed for an IOR/EOR pilot implementation in Woodbine field. Water and produced hydrocarbon gases were injected alternately as well as in co-injection mode, however no consistent incremental oil was observed. Injected gas and water broke through on the order of hours and days respectively. The injector showed more connectivity with one of the producers, suggesting a strong areal conformance problem. A steady baseline operation was established by co-injecting gas and water at a constant gas fraction and total constant rate that resulted in steady production baseline. The baseline injection was continued with surfactant injection in brine for in-situ foam generation. During five weeks of surfactant injection, foam generation and mobility reduction were confirmed with the increase in the measured bottom-hole pressure. Mobility control resulted in out of zone injection elimination for both gas and water and gas diversion to bypassed areas. With conformance corrected at the injector and deeper in the reservoir, oil production rates more than doubled, gas utilization was improved, and a low gas-to-oil ratio and improved volumetric sweep were confirmed. The increased oil production continued for at least 6 weeks after completing surfactant injection. More than 2000 bbl. of incremental oil was recovered in 11 weeks of pilot operation. Current work confirms the technical efficacy and potential of the gaseous foam conformance solution for incremental oil production in unconventional plays.
Petroleum produced from low permeability shales is different to the dispersed in-situ fluids from which it is derived. Whereas in-situ fluids consist of hydrocarbons, resins and asphaltenes in proportions governed by organic matter type, maturity and retention behaviour, the produced fluids are highly enriched in hydrocarbons and low polarity non-hydrocarbons, and show an enhanced GOR. Here, we study the effects of fractionation during production from Permian and Cretaceous shales using laboratory experiments, PVT-modeling and a regional PVT database. Our goal was to develop methodologies for predicting yields and compositions of produced fluids ahead of drilling.
Target wells with known fluid properties were used for calibration. Shales from neighbouring wells of slightly lower maturity were mildly matured to that of the calibration well using MSSV pyrolysis, and a PhaseSnapShot of the resultant fluid made using PVTsim.
The first example, from the late oil window Eagle Ford, demonstrates that both kerogen and bitumen are important petroleum precursors, and that in-situ compositions are largely determined by the most recently generated charge, rather than by cumulative addition during maturation. The PVT model, calibrated to the engineering report of the target well and its environs, reveals that a high proportion of the in-place C7+ fluids remain in the rock matrix relative to gas during production. The second example, taken from a gas and condensate fairway in the Permian Basin, shows that the predicted bulk composition of recently generated petroleum is facies dependent. PVT fluid calibrations have low Psat and low cricondentherms. These characteristics are reproduced by experiment, but only for those zones containing low contents of high molecular weight liquids. Any contributions to produced fluids from other zones is associated with massive retention of high molecular weight organics. The third example concerns volatile oil production from wells in the Permian Basin. The MSSV products generated by adjacent lower maturity shales exhibited phase envelopes with higher cricondentherms than that of the calibration, this being attributable to a molecular weight difference in heavy components. Adjusting the MW from 249 (measured) to 222 (produced oil PVT value) in the PVTsim model aligned the cricondentherms. This tuning step corresponds to the preferential retention of heavy polar compounds in the rock matrix during production. In a second step, 20% of the tuned MSSV-generated liquids are considered to be retained in the rock, thereby raising Psat. The result is an excellent match between the doubly tuned predicted phase envelope and that of the produced fluid. The preferential retention of polar compounds is also in line with this tuning step.
In summary, fractionation is part and parcel of production from shales. Up to 80% liquids retention relative to gas has been demonstrated. Production efficiency assessments are readily inferred from these data.
The extent to which fractionation occurs varies a lot, and has here been assessed by combining experimental rock geochemistry with PVT modeling (PhaseSnapShots), and using PVT reports on produced fluids for calibration.
Islam, M. S. (Dhofar University in Oman and Fault Analysis Group, UCD School of Earth Sciences, University College Dublin in Ireland) | Manzocchi, T. (Fault Analysis Group and Irish Centre for Research in Applied Geosciences, UCD School of Earth Sciences, University College Dublin)
Most petroleum reservoirs contain faults, and a major technical challenge in full-field flow simulation is to represent the effects of 3D fault zone structure within the 2D fault surface represented in the industry standard commercial simulator. Geometrical upscaling (GU) is sometimes performed to include these fault zones implicitly in the upscaled model, and in this study, a comparison is made of the accuracy and flexibility of different geometrical upscaling methods. The existing template-based geometrical upscaling (TBGU) method is compared to a new flow-based geometrical upscaling (FBGU) method. In both methods, the faults are represented in the upscaled flow simulation model implicitly as neighbor and non-neighbor cell-to-cell connection transmissibilities, which are determined from 3D fault zone structures, but these transmissibilities are calculated in very different ways. Both approaches require a high-resolution flow simulation model (referred as truth model in this paper) containing complex 3D sub-seismic fault zone structure explicitly, which is then upscaled using the two methods to take into account the influences of the fault zone geometry as across-fault and along-fault flow. The accuracy of the upscaling methods is examined by comparing the flow behavior of the high-resolution flow simulation model with that of model versions upscaled in the two different ways. Individual well performance for the high-resolution truth and the upscaled models reveal significant differences between the two methods, and indicate that the flowbased geometrical upscaling technique is a more accurate means of including structurally complex fault zones into low-resolution upscaled flow simulation model.