Recent studies have indicated that Huff-n-Puff (HNP) gas injection has the potential to recover an additional 30-70% oil from multi-fractured horizontal wells in shale reservoirs. Nonetheless, this technique is very sensitive to production constraints and is impacted by uncertainty related to measurement quality (particularly frequency and resolution), and lack of constraining data. In this paper, a Bayesian workflow is provided to optimize the HNP process under uncertainty using a Duvernay shale well as an example.
Compositional simulations are conducted which incorporate a tuned PVT model and a set of measured cyclic injection/compaction pressure-sensitive permeability data. Markov chain Monte Carlo (McMC) is used to estimate the posterior distributions of the model uncertain variables by matching the primary production data. The McMC process is accelerated by employing an accurate proxy model (kriging) which is updated using a highly adaptive sampling algorithm. Gaussian Processes are then used to optimize the HNP control variables by maximizing the lower confidence interval (μ-σ) of cumulative oil production (after 10 years) across a fixed ensemble of uncertain variables sampled from posterior distributions.
The uncertain variable space includes several parameters representing reservoir and fracture properties. The posterior distributions for some parameters, such as primary fracture permeability and effective half-length, are narrower, while wider distributions are obtained for other parameters. The results indicate that the impact of uncertain variables on HNP performance is nonlinear. Some uncertain variables (such as molecular diffusion) that do not show strong sensitivity during the primary production strongly impact gas injection HNP performance. The results of optimization under uncertainty confirm that the lower confidence interval of cumulative oil production can be maximized by an injection time of around 1.5 months, a production time of around 2.5 months, and very short soaking times. In addition, a maximum injection rate and a flowing bottomhole pressure around the bubble point are required to ensure maximum incremental recovery. Analysis of the objective function surface highlights some other sets of production constraints with competitive results. Finally, the optimal set of production constraints, in combination with an ensemble of uncertain variables, results in a median HNP cumulative oil production that is 30% greater than that for primary production.
The application of a Bayesian framework for optimizing the HNP performance in a real shale reservoir is introduced for the first time. This work provides practical guidelines for the efficient application of advanced machine learning techniques for optimization under uncertainty, resulting in better decision making.
Gas condensate reservoirs constitute a significant portion of global hydrocarbon reserves. In these reservoirs, liquids develop in the pore space once bottomhole pressure falls below dew point. This results in the formation of a liquid bank near the wellbore region which decreases gas mobility, which then reduces gas inflow. In such complex reservoirs, it is important to correctly describe PVT impacts, adjustments to well test analysis and inflow performance, and then combine all effects in the reservoir analysis. The literature contains many references to individual adjustments of PVT analysis, well testing, or inflow performance for gas condensate reservoirs, but few studies demonstrate the complete workflow for reservoir evaluation and production forecasting in gas condensate fields. This research uses a field case study to demonstrate an integrated workflow for forecasting well deliverability in a gas condensate field in North Africa.
The workflow incorporates a description of the retrograde behavior that impact the well deliverability. The workflow begins with the interpretation of open-hole log data to identify the production interval net pay and to estimate petrophysical properties. A compositional model is developed and matched to actual reservoir fluids. Several gas condensate correlations are used to obtain the gas deviation factor and gas viscosity in order to count the change in gas properties with respect to pressure. Transient pressure analysis is described and used to identify reservoir properties. Inflow performance relationships (IPRs) are analyzed using three types of back pressure equations. The workflow integrates all data in a numerical simulation model, which includes the effect of bottom water drive.
Results show that in this field case study, reservoir behavior is composite radial flow with three regions of infinite acting radial flow (IARF). Using compositional simulation, it is found that the fluid sample for this field is a lean gas condensate since the liquid drop-out represented 1% of the maximum liquid drop-out. In addition, liquid drop-out increases by 0.1% for every 340 psi drop in reservoir pressure, which reduces the AOF by 3.4%.
The results provided in this case study demonstrate the importance of an integrated workflow in predicting future well performance in gas condensate fields. The study demonstrates how to implement the workflow in managing or developing these types of reservoirs.
Although Trinidad and Tobago has an abundant supply of relatively pure CO2 and more than 1 billion barrels of heavy oil deposits there are no active enhanced oil recovery (EOR) projects using carbon dioxide (CO2).
In this paper, we have performed black oil simulation studies to evaluate several injection strategies with carbonated water, varying the salinity and viscosity of injected water. The salinity was varied by 1,000 and 35,000 ppm. The viscosity was increased by adding 0.1 weight percent polymer to injected water. The investigation was carried out using a commercial reservoir simulator. The simulation grid represents the properties of a quarter five-spot of the Lower Forest sand of the Forest Reserve Field. The reservoir simulation components used are water, polymer, H, Na, Cl-, dead oil, solution gas and CO2. The Stone #1 three-phase relative permeability model was used to calculate the three-phase relative permeabilities from two-phase data. In addition, a factorial experimental design was utilized and twelve simulation runs were done along with nine benchmark runs for comparison to other EOR methods.
From the results obtained the following was concluded: water salinity has no effect on either oil recovery or carbon dioxide storage; polymer injection increases oil recovery and carbon dioxide storage. We found the optimal injection strategy to be a cycling of carbonated water alternating with polymer injection.
This study investigates how compositional effects interact with the flow behavior during near miscible (and immiscible) CO2-oil displacements in heterogeneous systems. A series of numerical simulations modeling 1D slim-tube and 2D areal systems were performed using a fully compositional simulator. With negligible numerical dispersion, the fine-scale (Δx=0.005m) slim-tube simulations were performed to provide the "truth case" in terms of the compositional effects and oil/component recovery. A number of grid resolutions were tested to examine cell-size effects on the simulation accuracy. It was found that coarse cell size not only leads to spreading of the displacing front, but also lowers the displacement efficiency by reducing the component stripping effects, as noted by
To summarize, compositional effects can have a very significant impact on the prediction of near-miscible CO2 EOR projects. Issues such as front stability, local displacement efficiency and formation of fingering/channeling during CO2 near-miscible displacement can lead to behavior that is significantly different from immiscible flooding in these systems. The process of mass transfer between CO2 and oil can be hampered to a certain degree by unstable flow depending on the level of heterogeneity. This leads to a further reduction in component recovery, particularly of the heavier components. Lastly, the appropriate upscaling methods considering mass transfer still require further investigation for CO2 near-miscible displacement in field-scale applications. The complete dataset and results of this study are available online as a model case example for testing out potential upscaling techniques for compositional flows in heterogeneous systems (
A seminal event last year was the Climate Change Conference in Paris, where participating countries agreed to reduce their carbon output "as soon as possible" and to do their best to keep global warming "to well below 2 C." History will be the judge of whether 2015 turns out to be a turning point in the journey to reducing global warming. There is still a long way to go to turn good intention into substantive action if the world is to transition to a low-carbon economy and ultimately to one of net zero carbon emissions. This challenge is all the tougher given increasing demand for energy, with the International Energy Agency expecting growth by one-third between 2013 and 2040. In the US, there has been a gradual shift in the balance of enhanced-oil-recovery (EOR) production between thermal and gas-injection projects. Since 2006, production from gas injection has outstripped that from thermal, and it is continuing to grow.
The selection of the right polymer chemistry in chemical enhanced oil recovery processes is key to successfully increase oil recovery. To start the screening process, it is necessary to look at minimum 3 parameters including brine composition, reservoir temperature and permeability. In addition to simple rheological tests, it is mandatory to evaluate the long-term and shear stabilities of the polymer candidates to ensure that viscosity is maintained over time at an economical concentration. In few cases, the polymer that yields the best results (especially viscosity yield) at an instant t is not always the best compromise when considering long-term stability or shear sensitivity. This paper aims at providing some guidelines to select the optimum chemistry for a wide range of field conditions.
The resistance of different acrylamide and ATBS-based polymers to salinity and shear is evaluated through viscosity measurements over a wide range of brine compositions. A parameter called R+, that reflects brine hardness, is introduced in this study. Brines considered are either with a constant Total Dissolved Salt (TDS) and varying R+ or different total salinities with a constant R+. This parameter is also used to compare shear resistance of the different polymers.
For all the polymers, there is a threshold value of R+ beyond which viscosity remains constant. Interestingly, this threshold is reached for lower value of R+ for polymers containing ATBS, a monomer also well-known to provide calcium tolerance. Increasing the amount of ATBS yields better tolerance to divalent cations and provides shear resistance. A minimum amount of sulfonated monomer is required to improve the overall stability in complex brines.
Some important guidelines are summarized in this paper that can help screen products among a wide range of reservoir conditions in order to find the most suitable candidate for a chemical enhanced oil recovery project.
Belayim Land Field, located in the Gulf of Suez Egypt, is a giant brown oil field, characterized by medium viscous oil, currently developed by means of peripheral seawater injection. Several chemical EOR processes were investigated to increase oil production and maximize ultimate recovery. Among them, polymer flooding application was selected to improve the mobility ratio, leading to an increased oil recovery. An intensive work has been done starting from laboratory studies for proper polymer selection and characterization, tertiary core-floods with polymer solution, to a sector model. Later on a pilot test was designed to evaluate the EOR potential at the reservoir-scale before a polymer flooding full field project is implemented to address uncertainties and risks. Pilot project for polymer flooding has been established in Belayim Land Field, polymer injection has been started effectively in Feb-16 with an injection rate of 1,000 BPD and a polymer concentration of 1,500 ppm, therefore, a detailed surveillance and monitoring program has been prepared and implemented. This program was guided by way forward road maps that target injection, flooding performance, and production assessment.
The purpose of this paper is to highlight the work done from the design phase till pilot project implementation and start up, to present the lessons learned and best practices for operation’s continual improvement of such processes and to highlight also that quality-control is an essential element for the successful implementation of a polymer-water-flooding project. The monitoring program should include, but not limited, the routine verification of polymer concentration, routine determination of the viscosity, and periodical check of the thermal and chemical stability of the polymer.
Typically, about 70% of most proven oil reserves in the world remain untapped after primary drive mechanisms. Even after applying extensive waterflooding (secondary recovery) project, there remains a significant amount of the oil resource unrecovered as a result of reservoir heterogeneity and complex geology.
In April 2015 a Chemical Enhanced Oil Recovery (CHEOR) pilot unit located at the Belayim field (Abu Rudeis, Egypt) has been handed over to Petrobel. The Site Acceptance Test was successfully performed and it sanctioned the technology transfer from Eni headquarter to the End User. Chemical EOR technology aims at increasing water viscosity and improving sweep efficiency by using a polymer (polyacrylamide) in solution. The pilot unit has been designed to mix seawater and polymer, to properly prepare and mature the solution, and to inject it at high pressure into the well, thus enabling an increased oil recovery in mature field, where water cut tends to increase dramatically. The CHEOR project has been funded and managed by Eni and Petrobel in the frame of an R&D CHEOR Project (Chemical Enhanced Oil Recovery): major driver was an efficient and fast development of the technology, which had been already implemented in another Eni asset in Egypt. The whole project has taken 14 months to be completed, proving extremely successful in terms of schedule: such a result has been achieved through the integration into the project management team of different Eni disciplines such as EOR reservoir experts, headquarters laboratories, as well as Petrobel integrated team (Project, Reservoir and Operations). Project target was achieved thanks to Lesson Learned captured from the previous project in Egypt: team integration, early involvement of Belayim Field in the project, dedicated engineering focal point in Eni, technology single point of responsibility and early purchasing of bulk material have been the main key factors of project execution. Considering the experience matured in the previous project, basic and detailed engineering has been assigned to EniProgetti Egypt who confirm their capability of effectively supporting the engineering in all phases.
Liping, Xiong (Sinopec Exploration & Production Research Institute) | Yanli, Liu (Sinopec Exploration & Production Research Institute) | Danni, Shi (Sinopec Exploration & Production Research Institute)
This paper focuses on the tectonic evolution of the North African petroleum basins as the controlling factors on the major basins' formation, evolution and the hydrocarbon accumulation, analyzing the petroleum enrichment conditions and proposing hydrocarbon accumulation mode. The analysis concludes that the distribution of North Africa Basins is in regular east-west direction, clear depression associates with highland structure. The basins becomes gradually older from the west to the east, corresponding to the Western Paleozoic basin, the Middle part Paleozoic and Mesozoic superimposed basin and the Eastern Mesozoic-Cenozoic rift basin. Petroleum in the Middle-West basins is mainly controlled by western Hercynian tectonic movement with obvious NE - SW distribution character, while petroleum in the East basins controlled by the Alpine tectonic movement, showing NW-SE distribution. Experienced a number of north-south direction reversals, the Paleozoic basin developed in the South and the Mesozoic -Cenozoic superimposed basin overlaying the Paleozoic Basin located in the North. The basins have two different accumulation models, which are younger source rocks associated with the older reservoirs and the older source rocks with the younger reservoirs.
Prediction of permeability in un-cored intervals is necessary to developing an effective reservoir characterization program. In this paper routine core analysis and well log data of an actually existing shaly sand reservoir in the Berkine Basin (Algerian Sahara) were used to develop permeability correlation using a Hydraulic Flow Unit approach (HFU). The core data were statistically treated for identification of Hydraulic Flow Units. This involves the calculations of Reservoir Quality Index (RQI) and Flow Zone Indicator (FZI). Obtained results show that five HFUs are identified from core data and each unit has its own FZI. A correlation between FZI calculated from core data and that obtained from well log data is developed for estimating permeability in un-cored intervals.
Presentation Date: Monday, October 17, 2016
Start Time: 3:20:00 PM
Location: Lobby D/C
Presentation Type: POSTER