Narcizo, O. Melo (PEMEX) | Aguilar, A. Martinez (PEMEX) | Mendo, A. Rosas (PEMEX) | Gordillo, J. C. (PEMEX) | Ramondenc, P. (Schlumberger) | Burgos, R. (Schlumberger) | Basurto, J. R. Cervantes (Schlumberger) | Rodriguez, F. L. (Schlumberger)
An innovative approach to underbalanced perforating in horizontal and highly deviated wells uses a new perforating head specifically developed to leverage the conveyance and real-time telemetry capabilities of coiled tubing (CT) equipped with fiber optics. The results and advantages of this approach have been demonstrated in wells in mature Mexican fields featuring significant reach and pressure limitations.
In recent years, CT equipped with real-time fiber-optic telemetry has been a method of choice to perform interventions in deviated or horizontal wells, as it provides a cost-efficient and flexible alternative to heavier wired CT. In the Mexican fields, this real-time telemetry capability is used to accurately place the guns thanks to downhole casing collar locater and gamma ray tools. The need for pumping fluids to enable detonation, often performed during typical CT perforating operations, is eliminated through the use of a downhole microprocessor-controlled firing head, which is directed by commands sent from surface through the optical fiber.
The result is a nearly instantaneous detonation downhole and positive confirmation provided in real time through an array of sensors in the bottomhole assembly (e.g., accelerometers, pressure, and temperature). The absence of working fluid eliminates any concern of hydraulically loading the well or the need for shut-in, thus significantly reducing the extent of deferred production. It also mitigates uncertainties linked to the influence of downhole conditions on the behavior of working fluids or the potential malfunctions of drop balls. This system is capable of multizone, selective detonation, therefore improving operational flexibility through reduced gun runs. It is also compatible with any other traditional CT service and can easily be combined with a bridge plug setting, a nitrogen lift, or a cleanout within the same run. The approach and its associated workflow enabled a significant reduction in intervention turnaround time by cutting as much as 75% of the time necessary to detonate the guns once the depth has been correlated, while providing fast and clear confirmation of downhole detonation.
This evolved approach not only addresses the conveyance limitations of highly deviated and horizontal wells, it also greatly improves the safety, reliability, and efficiency of underbalanced perforating interventions by leveraging the real-time downhole monitoring and control capabilities of CT with fiber optic telemetry.
Carbon Capture and Storage (CCS) is particularly attractive for the oil and gas industry due to the potential of Enhanced Oil Recovery (EOR). The presence of adequate well injectivity is identified as a prerequisite for CCS and CO2 EOR projects. Mineral precipitation in the vicinity of the well is suggested as a possible injectivity impairment mechanism. After mineral precipitation and formation dryout, continuous injection of CO2 into the formation could redistribute precipitates and alter injectivity. In this work, we investigated the effect of viscous force on precipitated minerals and the resulting consequences on permability and injectivity. The influence of supercritical CO2 injection rate, initial core permeability and saturating brine salinity were investigated. We observed that, injectivity impairment has a maximum immediately after mineral precipitation. Continuous injection of supercritical CO2 into the core after mineral precipitation is seen to reduce injectivity impairment induced by precipitated minerals. In most numerical and geochemical models, static injectivity impairment as a result of mineral precipitation is often assumed. Our findings suggest that injectivity remains dynamic throughout the injection process. Therefore, changes in CO2 injectivity after mineral precipitation could be complex to model and understanding of the processes is a good point to start.
Chemical EOR is one of the promising methods to improve the oil recovery. However, due to high cost of the process, there are challenges to minimize the cost and maximize the oil recovery. Some influencing parameters should be taken into account in a systematic approach to find their impact on oil recovery and accordingly optimizing the process.
In this study, we present a robust optimization workflow of alkaline-surfactant (AS) flooding into a thin clastic reservoir of a field in the Malay Basin. There are coreflood experiments and pilot tests on this field that can be quite helpful to provide a basis to find out the appropriate range of input parameters. Optimization work is based on response surface methodology (RSM) and particle swarm optimization (PSO) technique that aid us to indicate the optimum oil recovery from chemical flooding. In order to get the utmost advantage of this workflow, the waterflooding should be optimized prior to the chemical flooding optimization to maximize the sweep efficiency and oil recovery from the chemical flood.
Evaluation of coreflood and pilot tests indicated that some parameters need supplementary evaluation to investigate their effect on reservoir performance and flow dynamics. These parameters include residual oil reduction by chemical, relative permeability curves, chemicals adsorption, chemical concentration, slug size, injection rate, and initiation time of chemical injection. Based on the result of tornado chart, residual oil reduction and injection rate exhibited highest and lowest impact on oil recovery. RSM was used to explore the relationship between input variables and objective function. Some design parameters such as chemical concentration, slug size and initiation time were examined in this stage. Afterwards, proxy models have been built using polynomial regression and neural network methods. The results showed that the proxy model by neural network method revealed better performance for prediction of the simulation results. The proxy model was used to calculate the oil recovery for any combination of input parameters. Besides, it was used to assess the parameter sensitivity and identify the impact of any input parameter on oil recovery. At the next stage, PSO method was utilized to optimize the oil recovery by chemical flooding. It was found that the optimized water injection rate and pattern for water flooding scenario need further optimization to improve the sweep efficiency and thereby oil recovery by AS flooding at later stage. Running numerous simulation cases is normally expected to optimize the process by conventional methods and the proposed PSO approach can be used to reduce the number of runs significantly. Sensitivity analysis provided a very good understanding about reserve ranges for the different influential parameters. Optimizing the cost of chemical flooding and improving oil recovery are other outcomes of this study.
In the past decade, Fiber-Optic (FO) based sensing has opened up opportunities for in-well reservoir surveillance in the oil and gas industry. Distributed Temperature Sensing (DTS) has been used in applications such as steam front monitoring in thermal development projects and injection conformance monitoring in waterflood development projects using warmback analysis and FO-based pressure gauges are deployed commonly. In recent years significant progress has also been made to mature other, new FO-based surveillance methods such as the application of Distributed Strain Sensing (DSS) for monitoring reservoir compaction and well deformation, multidrop Distributed Pressure Sensing (DPS) for fluid level determination, and Distributed Acoustic Sensing (DAS) for geophysical and production/injection profiling. For the latter application, numerous field surveys were conducted to develop evaluation algorithms to convert the DAS noise recordings into flow rates from individual zones.
In this paper we present an overview of recent advances in FO-based methods such as DAS, DTS, and DSS for the application of production and injection surveillance. From field examples acquired by Shell and its affiliates it is clear that FO-based flow monitoring provides a powerful addition to the standard surveillance toolkit and in some cases is even the preferred way of surveillance because of its unique advantages.
Ferrandis, Javier (Shell Intl. E&P and Alejandro Girardi, Shell Brasil) | Cantelli, Alessandro (Shell Intl. E&P and Alejandro Girardi, Shell Brasil) | Jimenez, Eduardo (Shell Intl. E&P and Alejandro Girardi, Shell Brasil)
Some of the current methods of geological modeling cannot imitate the order and complexity that is observed in nature. It's been recognized among the geoscientist community how a process-based modelling may facilitate a step change in reservoir building capabilities. The advantage in decoupling the grid design from the facies distribution poses a tremendous opportunity to close the gap between the static and dynamic reservoir model. A major advantage is capturing fine-scale heterogeneities (shale drape, amalgamation, etc) which are hard to capture with pixel-based techniques. The goal of process-based geological modeling is to simulate that order by generating rules. These rules make possible to create high-fidelity 3D geological models representing more realistic depositional and stratigraphic events than those that are randomly generated using conventional geostatistical techniques.
In this paper we illustrate the use of surface-based modeling within a submarine-turbiditic environment and the procedure followed to deliver a dynamic model conditioned to production data. The procedure follows development of physics-based methods and rule-base stacking of events to reconcile geological complexities and uncertainties with well performance. We'll present a process combining Design of Experiments and gradient-based techniques to assimilate production data. The method generates complex geometries comparable to those observed in high resolution near-surface seismic datasets. The case under consideration is an oil field offshore Brazil developed with horizontal wells and state of the art surveillance. The proposed workflow has delivered a simulation model that has achieved a good history match to production data in the form of water cuts and pressures.
The ability to access and share one valid and up-to-date technical information is a key element of our efficiency with the follow-up of our projects and operations. This will have a critical impact in case of incidents and/or crisis situations, as this could happen in sensitive areas like in the Middle-East or West Africa.
In case of a major crisis, we must be able to restore the access to the GIS data identified as critical within a time limit of 4 to 8 hours!
This paper presents the lessons learnt from a seismic reprocessing performed to improve the seismic reservoir characterization of a Middle East carbonate reservoir. The reservoir characterization objective is to optimize the porosity modeling driven by seismic data; hence, improving seismic amplitudes was crucial as they drive the inversion process for elastic properties. The new seismic reprocessing sequence was focused on the restoration of genuine primary amplitudes and improvement of the angle stacks design at the reservoir. In order to monitor the seismic amplitudes quality improvement throughout the processing sequence, a thorough quality assessment strategy has been implemented for decision making. It has allowed adjusting the amount of testing depending on the quality of intermediate results at selected key steps. The results obtained by using this QC strategy showed the importance to monitor in details the amplitudes quality progress by tuning at an early time the processing parameters that impact all the remaining steps. At the end of the reprocessing, a cleaner dataset, less affected by multiples interferences, with a more consistent amplitude balance and optimized angle stacks design has been obtained. It is deemed to be more appropriate for pre-stack inversion purposes in view of seismic reservoir characterization.
The objective of this paper is to present the feasibility study carried out –in a carbonate field context– on the integration of stochastic inversion and classification results in a geological modeling workflow. Indeed the geological model is based on a seven –log defined and core calibrated– electrofacies scheme while the stochastic seismic inversion and classification provides P and S-Impedances (IP & IS), Poisson's ratio (PR) and lithology probability of occurrence cubes. Making the link between lithologies –limestones and dolostones in our case– and the electro facies scheme is the main topic addressed in this feasibility study.
Al-Jaadi, O. S. (Qatar Petroleum) | Sugiharto, A. (Qatar Petroleum) | Srivastava, A. K. (Qatar Petroleum) | De Almeida Netto, S. L. (Qatar Petroleum) | Bliefnick, D. M. (Qatar Petroleum) | Djebbar, Z. (Qatar Petroleum) | Al-Ali, M. A. (Qatar Petroleum) | Kamal, M. A. (Qatar Petroleum) | Abdo Aly, T. M. (Qatar Petroleum)
The presence of shallow gas pockets, karsts and dissolution features in proximity to faults is a common geological phenomenon in carbonate reservoirs. Such subsurface features have been known to have an impact on well planning, assessment of hydrocarbon volume in place, well management and overall development strategy. Therefore, there is a strong business case to identify and map out these features in detail for field development purposes.
The presence of karstification in carbonates causes heterogeneity at various scales. In the Bul Hanine Field, several wells have experienced losses of various degrees. Mud losses at the reported depths have been correlated with the presence of karst-related features. Knowledge of the distribution and geometries of the karst geobodies in carbonates is essential for well planning and reservoir modelling. The geohazard recognition and modelling workflows described in this paper rely on the integration of available subsurface data. Evidence of karst features was characterized with 3D seismic data, core, log and production data. Using Petrel geobody mapping techniques, the karst was picked as 3D geobodies which were then extracted based on optimized clipping parameters of the various seismic attributes. This was performed after the separation of actual signal versus noise. Several sensitivities were performed in order to optimize the final result before being integrated into a geo-cellular model.
An integrated geohazard workflow on the Bul Hanine Field revealed the presence of four distinct types of geohazards which were observed at various stratigraphic intervals. Various seismic characterization techniques were deployed to detect and map karst-related geobodies. These geobodies were then incorporated into a 3D geo-cellular model and their impact on volumes was assessed. A more detailed geohazard analysis was then performed along the trajectory of the planned wells minimizing operational risks.
Exploration for oil and gas in the ancient Paleozoic–Proterozoic Taoudenni cratonic basin has been revived in the recent years following the documentation of a viable and efficient petroleum system in the Adrar region of Mauritania. In order to gain better knowledge of the thermal history prevailing in the prospective area (Ta7-Ta8 blocks), extensive fluid inclusion and thermochronology studies have been conducted on outcrop samples as well as cores from recent and older wells in the Paleozoic and Proterozoic sections. The results indicate that the Adrar region was affected by complex and variable burial-thermal regimes. A major cooling-uplift event is documented at ~100–150 Ma, possibly resulting in as much as ~3 km sediment removal. Maximum burial temperature in the Proterozoic formations reached ~140–180°C depending on location. Higher temperatures (>200°C) are recorded which are attributed to short-lived heating events related to diabase emplacement, but no evidence supports a uniform thermal event of regional extension. Cooler burial-thermal regimes may have prevailed in the North-Eastern part of the prospective area. Record of petroleum migration is limited to the Meso-Protrozoic and lowermost Neo-Proterozoic formations, below the Lower Assabet (I14) regional seal. This work provides valuable information for future exploration of the Proterozoic section in this part of the Taoudenni basin.