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Africa (Sub-Sahara) The drillship Ocean Rig Athena is preparing to drill appraisal and exploration wells offshore Senegal for a joint venture (JV) led by Cairn Energy. Two wells will appraise the SNE discovery, which was ranked by IHS CERA as the world's largest for oil last year. An exploration well will also be drilled in the Bellatrix prospect, for which mapping has indicated a potential 168 million bbl of oil resources. Cairn holds a 40% interest in the JV, with remaining interests held by ConocoPhillips (35%), FAR (15%), and Petrosen (10%). The Ksiri West-A exploration well drilled by Circle Oil on the Sebou permit onshore Morocco has flowed gas at a rate of 8 MMcf/D following tests. It is being readied for production.
The Magallanes Basin of Southern Chile is the southern-most hydrocarbon-producing basin in the world. The main source of the gas production in this basin is from the Glauconite Formation. The Glauconite is a clay and feldspar rich formation with extremely low permeability requiring hydraulic fracturing to recover the hydrocarbons and enhance well performance. In this project, fracture simulations with a fully three-dimensional finite element model were integrated with statistical analysis and used in an optimization study of hydraulic fracturing in the Glauconite Formation.
The mechanical earth model was used to estimate the in-situ stress contrast, Young's Modulus, and leak-off profile with depth. Tri-axial compression tests of core were used to validate static Young's Modulus estimates while mini-frac data and fracture stimulation data were history matched and used to validate and/or modify in-situ stress and leak-off profiles with depth. The history matched treatments were then used to populate the database with the resulting hydraulic and propped fracture dimensions. Ultimately, a database that includes in-situ stress, stress contrast, Young's Modulus, leak-off, propped and un-propped fracture dimensions (length and conductivity) was developed.
Finally, both the database and multi-variate statistical analysis were used to show the role of mechanical earth modeling in enhancing and improving the understanding of fracture optimization in the Glauconite Formation. Results from hybrid fracture fluid treatments were compared to treated water fracture treatments to determine the optimum fracture stimulation design for this unconventional extremely tight gas resource.
This work provides a benefit to the petroleum industry by: Using a geo-mechanical finite element model to improve the understanding of the propped fracture dimensions achieved by hybrid and treated water fracture treatments in an unconventional resource like the Glauconite Formation. Establish the key drivers for successful water-frac treatments.
Using a geo-mechanical finite element model to improve the understanding of the propped fracture dimensions achieved by hybrid and treated water fracture treatments in an unconventional resource like the Glauconite Formation.
Establish the key drivers for successful water-frac treatments.
This work shows the realization of a
To do the feasibility analysis we use wells basics curves envelops. Combining with core analysis a static facies model was generated. Using averages of rock and fluid parameters along with the history of production and injection, a dynamic model was initialized. This model permits to do a "History Match" at field level. This allowed visualizing the evolution in time of displacement of fluids, product of the water injection.
The conclusions of this model define continuity with the conceptual model using a complete petrophysical study (VCL-Phie and Sw).
Combination of the results of SP and short resistivity envelopes yielded to a first approximation of a Vclay. From there a binary log was generated. Settle the same curve with a vertical proportion curve; reference levels used to separate the model in zones were defined. The study of cores fostered a relationship between facies and resistivity. To make a reliable 3D structural model the control was made by some surfaces created on well tops by correlation. In this static model were charged all wells data available (perforations, facilities, production and injection). Along with rock properties and fluid average, the model was initialized.
At this stage of visualization, a quick historical setting, at field level, injection and production served to understand the behavior of fluids in the reservoir. This understanding in the changes of water saturation turns to be a very important input for the next phase of conceptualization.
Having a static and dynamic visualization model purchase in both ways the conceptualization phase, whether or not pass to the next stage. Everything done in the first stage is the starting point of the next (Front End Loading - FEL).
The FEL methodology is deeply rooted in the DNA of YPF. In this case, with software who allowed enhancing this work process, creating a unique project where all available parameters are incorporated, with the possibility of being used in the different phases of the study. At the same time, each analysis on the project, adds value to the next step. This work allowed to reservoir engineer of this field to improve the oil recuperation factor.
This contribution presents the concept of auto-injection with mechanical pump, as an alternative to the initial stage of a waterflooding project without the prior need of building a water treatment and injection pilot plant, aqueducts and injection lines (facilities). This case of study shares the results of this technique applied for first time in the development of a marginal oil field called Cerro Piedra, operated by YPF on the western flank of San Jorge Gulf basin (Patagonia, Argentina).
The auto-injector, unlike a multilayer conventional injector, is self-sufficient and simple injection. It produces and injects briny water in the same wellbore; it is not required to invest on facilities to evaluate waterflooding response. Moreover, it forwards the start of injection and consequently quickens the reservoir's response improving project's profitability.
The fluid enters to the mechanism's circuit by a crossflow piece, where a hollow mechanical pump, driven by an individual pumping unit and hollow rods (4,600 ft maximum depth), produces up to 700 STB/D of water to the wellhead and pressurizes it up to 2,000 psia. At the surface, a measuring bridge registers flow, pressure and temperature. Finally, the pressurized fluid reenters to the well by the annular tubular-rod and passes through the crossflow piece to the injection zone.
The oil field is located 75 miles far away from Las Heras (Santa Cruz, Patagonia Argentina) and 40 miles from the nearest water treatment plant. The San Jorge Gulf basin is filled by a sequence of fluvial sediments which generate thin and low areal extent multilayer reservoirs. Bajo Barreal sedimentary unit is characterized from top to bottom by: briny water levels (3,500-8,000 ppm) to oil productive levels reservoirs. This distribution allows the auto-injector to produce shallow briny water layers and inject it into deeper hydrocarbon reservoirs.
The project includes an initial pilot phase to evaluate the waterflooding response, established with five auto-injectors; an intermediate stage of full development, developed by the completion of the water treatment and injection plant and conversion of eight selective injectors; and a final conversion phase, where the auto-injectors are reconverted to traditional injectors.
This auto-injection strategy allows us to evaluate the waterflooding response in a marginal virgin zone, without needing to build facilities for water treatment. Therefore it gives a sustainable water management of the field. This alternative approach improves at least 2% of original project's profitability, which was planned with the construction of an injection pilot plant.
The current low oil price scenario makes it increasingly critical to build robust business cases, to model uncertainty and to identify the most efficient and economically viable scenarios for any field development or redevelopment strategy.
The purpose of this paper is to present a multi-scale reservoir modelling approach to assess economic viability for the development of an EOR project in an adverse oil price scenario. We present an on-going polymer injection project in a brown oil field in the Western Flank of the Golfo San Jorge Basin in southern Argentina as case study for this methodology. Productive interval consists of a 1000 meters-thick low net-to-gross fluvial succession, in the Cretaceous Bajo Barreal Formation. The field produces a ~100 cp oil with very low recovery factor and a watercut of 94%, after 25 years of waterflood.
The need for high resolution models is validated by a cell size sensitivity analysis on polymer injection simulations. We verified that almost 50% error on oil incremental forecasts by polymer injection is obtained if 50 × 50 m cells were used. Therefore, combining purpose-built dynamic models in different scales and economic evaluation we support the on-going execution of the EOR pilot project. Several static/dynamic models are built at different scales (from 10 km to 100 m) to capture depositional trends and model stratigraphic and sedimentary heterogeneities. We evaluate different physical aspects of the polymer injection process with specifically designed numerical simulations at appropriate resolution. We think that detailed modelling and data acquisition are highly profitable decisions even in current challenging economic scenario, aiming at reducing uncertainty and strengthening business cases. Indeed, laboratory and field measurements, identification of critical variables, and high resolution modelling proved to reduce forecast uncertainty and strengthen business case economic indicators.
The purpose of this paper is to present some alternative workflows and methods that can be used for a quick initial reservoir characterization. We apply these methods in different fields to analyze stratigraphic correlation, sand distribution, and recovery opportunities.
We analized Spontaneus Potential (SP) and Resistivity (R) logs, the only two curves run in the wells of the old mature fields studied. We built envelope curves for them, which are moving window averages that capture SP or R values for shales and clean sands. These curves are applied to compute the shale volume (Vsh) as an automatic multiwell process that takes into account formation and well variations in a simple way. We compared this Vsh with a traditional petrophysiscal interpretation and showed good validation results in many oilfields. We used this Vsh to build a simple sand-shale log and then a 3D model, analyzing spatial trends and connected volumes, which helped visualize main production units and waterflooded intervals. By means of simple calculations, it is also possible to determine non perforated hydrocarbon-bearing sands, and obtain a list of workover opportunities in a quick way. Zones for a possible EOR project could also be determined.
Additionally, we computed a derivative for the base envelope curve of R, which shows large scale variations in rock properties. We find vertical patterns in wells that can be followed for long distances, showing great lateral continuity, and helping determine a stratigraphic correlation between different oilfields. Although it has low resolution, it captures the main stratigraphic features.
Lastly, we computed a probabilistic forecast in 3D for each fluid type observed at swabbing tests. This is a routine workflow based on nearby swabbing tests, and should be simply used as a quick guide.
The envelope curves proved to be useful for a quick log normalization, baseline shift correction, Vsh calculation, and regional trend analysis. All these approaches are very effective in big fields with hundreds of wells and multiple layered reservoirs due to the speedy methodology. They are useful in visualization stages as an initial project overview.
The case study here presented supports the on-going EOR development project of a low net-to-gross fluvial system producing viscous oil form a thick sedimentary column in San Jorge Gulf Basin, Argentina. The selected strategy consists in combining dynamic modeling, analytic tools and field measurements to assess field potential and to model uncertainty through different yet plausible deterministic scenarios.
The selected area is Los Perales field in Southern Argentina, with 2880 wells producing from more than 1000 m thick column of thin fluvial sandstone bodies and tuffaceous shale floodplain intercalations. This is a mature field extensively drilled, although single sand extension is likely to be below well spacing. Sands are captured by well logs but have no seismic representation, making connectivity prediction in between wells critical for any IOR or EOR project. For this reason, sand lateral connectivity is estimated by statistical tools, and then several plausible 3D connectivity scenarios are used to model geological uncertainty. Simple analytical tools support simulation results on the identification of key dynamic factors affecting polymer flood incremental volumes. Nevertheless, different modeling approaches are here combined to build deterministic scenarios such as fine scale 2D section models and different resolution 3D sector models for different purposes.
We estimate that, given the adverse mobility ratio, when 45% water saturation is reached in the reservoir water sweep efficiency becomes so dramatically low that almost no oil is pushed and water cut raises over 95% as historical production data shows during the 25-year water-flood history in the field. The resulting low recovery factor presents a huge opportunity for polymer flood not only in the already swept areas and heterogeneous regions but also in some unproduced layers with water forecast on swabbing tests. A zone-ranking based on a vertical proportion curve for reservoir and non-reservoir intervals allows us to narrow the development to lower risk confined regions. Further investigation and detail modelling in these regions permit us to assess uncertainty and estimate incremental volumes as up to 3 times those recovered by water-flooding. Production logging confirmed the relevance of targeted intervals in well production, hence supporting polymer business case.
This methodology is used to forecast, rank and select the best areas for polymer flood. This integrated approach combines geology, petrophysics and engineering using several laboratory tests, multiple deterministic scenarios and statistical tools to analyze polymer flood opportunities in a large field producing from a low net-to-gross thick sedimentary column.
The aim of this work is to evaluate the desirability of conducting the History Matching using flow lines instead of traditional simulation. The results are very encouraging. The simulation time was reduced to a 10% from its original value, with a very good match. This was subsequently confirmed with a traditional simulation.
The San Jorge basin (CGSJ), located in southern Argentina, extends over the central part of the Patagonian region. The sedimentary fill of the basin is related to different rift and sag tectonic phases, from Triassic to Cretaceous. During Late Cretaceous-Early Tertiary, a marine transgression from the Atlantic developed. Tertiary sediments completed the basin fill. Sediments from continental rivers form a huge overlying of fluvial-shallow lacustrine units deposited under late sag conditions. These units contain the reservoirs that host the hydrocarbon accumulations of the basin. The study area to be developed by Secondary Recovery has more than 250 reservoirs and 300 drilled well. The drenage radio is about 150 mts. The average production of each well is around 15 Bbl/d.
As part of the Reservoir Caracterization, a high-resolution reservoir model was build. The model contains 5.4 million cells (1.1 are active) with 290 producing layers and 260 wells. Production started mid 1993 (22 years of History). Water flooding started 2002 when 21 wells were converted to injectors. It's a simple grid with 50 to 50 meters by cell. A conventional simulation run takes 12 hours. No assisted history matching was possible, due to the size of the model. With the use of a fast flow simulation technique, streamlines, the time was reduced to 2.5 hours. This makes possible to work over the simulation parameter. With this normal simulation time, enough runs were done to match pressure behaviors and field productions. So, a standard history matching workflow was used with the exception of flow lines to perform the simulation runs.
The use of stream lines reduced nine times the standard simulation time. Thanks to this, it was possible to manually iterate the model parameters, doing each time a new simulation run to evaluate results. This work methodology allowed the correct understanding of Reservoir drainage mechanism. With all this, history match was done in a reasonable time. The absolute difference in liquid production was less than 12%. Finally, a conventional run was performed to verify the consistency between the two methodologies. In this case, the difference between both runs is imperceptible. This confirms that the use of strem lines is an excellent tool to adjust big size models.
Britt, L. K. (NSI Fracturing, LLC) | Otzen, G. (ENAP) | Guzman, M. (ENAP) | Kusanovic, G. (ENAP) | Alqatrani, G. (Missouri University of Science and Technology) | Dunn-Norman, S. (Missouri University of Science and Technology)
The Glauconite Formation in southern Chile is an unconventional resource made up of approximately forty percent clay and glauconite, thirty-four percent feldspar, twenty-three percent quartz, and three percent tuff. Like many unconventional reservoirs outside the United States, establishing commercial production from the Glauconite Formation was difficult given the make-up of the reservoir, the availability of equipment and materials, and the logistics associated with drilling, completing, and fracture stimulating wells in a remote area like Tierra del Fuego in southern Chile.
This paper describes the effort to establish commercial production from the Glauconite Formation beginning with a couple of marginal wells in late 2011 through a nearly seventy-five well development by early 2016. As part of this effort, a basis of fracture design was established by developing a profile with depth of in-situ stress, Young's Modulus, and leak-off coefficient. These geomechanical assumptions were then tested and modified with core and pump-in data and used to make revisions to the fracture stimulation design. The designs were optimized to ensure that the critical fracture dimensions (fracture length, conductivity, and height) were achieved to maximize well performance.
Next, a data collection plan was developed to capture key information about completions, mini-frac analysis, fracture design and execution, fluid, proppant, and chemical additives, reservoir quality, and post fracture flowback and clean-up data. The database was then utilized to monitor the Glauconite fracture stimulation program to ensure that the basis of design for the fracture program maintains viability and to ensure that the appropriate equipment and materials were mobilized for fracture optimization and to meet the program objectives.
This paper focuses on the key elements of well completions and fracture stimulation practices as they apply to tight gas and unconventional formations by using the database to manage project risks and develop appropriate mitigation strategies. For example, preliminary fracture stimulation designs were based on initial reservoir permeability estimates of 4 md, however, the data collection plan incorporated a well test program which determined that the actual reservoir permeability was nearly one thousand times less.
Another example was the rock mechanics and geomechanical data derived from dipole sonic logs indicated little in-situ stress contrast and raised concerns about the ability to achieve the desired fracture dimensions. In addition, the log derived Young's Modulus was low and inconsistent with the core tri-axial compression and ultrasonic data as well as the on-site mini-frac net pressure data. As a result, a number of tri-axial compression tests were conducted and it was determined that the Young's Modulus was much higher than indicated from the logs. The collected data and monitoring program resulted in significant treatment modifications ranging from the small cross-linked stimulations conducted initially to linear gel, hybrids, and ultimately treated water fracture stimulations as equipment and materials became available. This work is beneficial as it:
Conducts an indepth well analysis and evaluation to develop a basis of fracture design, Builds a database of important reservoir quality, completion, mini-frac, fracture, and post fracture clean-up data, Utilizes the database to monitor the fracture design basis, manage material and equipment needs in a remote area, and to maximize well performance.
Conducts an indepth well analysis and evaluation to develop a basis of fracture design,
Builds a database of important reservoir quality, completion, mini-frac, fracture, and post fracture clean-up data,
Utilizes the database to monitor the fracture design basis, manage material and equipment needs in a remote area, and to maximize well performance.