This paper describes the selection, design, successful application and performance monitoring of Electrical Submersible pumps in the giant Mangala oil field and Thumbli water field situated in the Barmer basin in Rajasthan, India. Mangala oil field contains approximately 1.3 billion barrels of STOIIP in high-quality fluvial reservoirs. The field was brought on production in August 2009 and is currently producing at the plateau production rate of 150,000 bopd of which approximately 40% of the oil production is from the ESP oil wells.
To support the water requirement of Mangala and other satellite oil fields, Thumbli source water field was developed with 5 water production wells with up to 4 wells operating at a time. Each of these water wells is installed with 60,000 bwpd capacity pumps and the field is currently producing up to 225,000 bwpd to meet the water requirements of Mangala and other satellite fields.
The Mangala oil field is a multilayer, multi-Darcy reservoir, has waxy viscous crude with in-situ oil viscosity up to 22 cp and wax content in the range of 18 to 26%. The field was developed using hot water flood for pressure maintenance. Significant production challenges included unfavorable mobility ratio with early water cut and hence the early requirement of artificial lift to maintain the plateau production rate. The field has 12 horizontal producers and 100 deviated producers. ESP was selected as the artificial lift mode for the high rate horizontal producers while hot water jet pumping was selected as the artificial lift mode for low rate deviated oil wells. Each horizontal well is capable of producing up to 15,000 blpd and high rate ESPs were designed and installed to deliver the production requirement. Currently 8 of the 11 horizontal producers are on ESP lift and the remaining three wells are planned for ESP installation in the near future. Apart from two early ESP failures during installation, ESPs have had a good run life; the paper also describes lessons learnt from the infant mortalities.
The Thumbli water field, located ~20 km southeast of Mangala field has been developed to meet the water requirement of Mangala and other satellite fields. Thumbli water aquifer is a shallow water field which contains water of ~ 5000 ppm salinity with dissolved CO2, oxygen, chlorides and SRB. 5 high capacity water wells were drilled in Thumbli field to meet the huge water demand from Mangala for water injection in Mangala and satellite field injector wells, hot water circulation in oil production wells and associated water requirement for boilers etc. 1000 HP water well ESPs were designed to produce up to 60,000 bwpd from each well with installed water production capacity of up to 300,000 bwpd from Thumbli field.
Over the last several years, horizontal drilling and multi-stage hydraulic fracturing have become the norm across the industry and proved crucial for economic production of natural gas from unconventional shale gas and ultra tight sandstone reservoirs, also referred to as nano-Darcy reservoirs.
Following the success of the Barnett shale, horizontal drilling and multi-stage hydraulic fracturing has spread across North America with new emerging shale gas plays such as the Eagle Ford, Woodford, Haynesville, Marcellus, Utica, Horn River
changing the industry's landscaping. In the current economic environment of high drilling and completion costs, coupled with lower commodity prices, the economic success of shale gas developments has become reservoir specific.
Evaluation of well's initial performance in a particular field and especially the ability to accurately predict the long term production behavior and EUR is critical to the efficient deployment of large capital investments. Field analogies making use
of arbitrary "type curves?? can have a significant negative impact on the project's bottom line.
With the growing number of multi-stage horizontal wells producing from shale gas reservoirs, many "unconventional?? production analysis techniques have been developed based on new concepts such as stimulated reservoir volume (SRV),
fracture contact area (FCA), or sophisticated mathematical relationships (power law decline curves, linear flow type curves, to name a few). These sophisticated engineering processes are well documented in the literature and have been presented at
numerous industry work shops and conferences. However, for the majority of these techniques there is one common reoccurring theme: performance evaluation of shale gas production cannot be analyzed using conventional methods (e.g.
This paper will demonstrate how the conventional approach of reservoir characterization, well performance evaluation and forecasting, can be implemented for all unconventional gas reservoirs, using traditional well testing and production data
analysis techniques. We will present one simple analytical model based on the solution of the pseudo steady state equation and will introduce the concept of a shale gas normalized production plot. In our view, the shale gas normalized production
plot is one type curve generally applicable to any shale gas reservoir.
Finally, pre-frac in-situ testing techniques will be reviewed and special consideration will be given to the perforation inflow diagnostic (PID) testing. We will emphasize the importance of specific reservoir parameters (pore pressure and in-situ shale
matrix permeability) and show their impact on drilling and completion strategy and design. Field case examples including well test results and production data from wells completed in several shale gas reservoirs are presented.
Pei, Peng (Department of Geology and Geological Engineering, University of North Dakota) | Zeng, Zhengwen (Department of Geology and Geological Engineering, University of North Dakota) | Liu, Hong (Department of Geology and Geological Engineering, University of North Dakota) | Ahmed, Salowah (Department of Geology and Geological Engineering, University of North Dakota)
Exploitation of thin oil zones in a mature field with complex carbonate geology under strong water drive offers many challenges. The primary objective is effective oil recovery from the thin oil zones without excessive water production. The initial development phase targeting thin remaining oil zones in a giant, mature carbonate field in Saudi Arabia has been guided by reservoir simulation results, with performance generally exceeding expectations. However, performance of individual horizontal wells has varied greatly. Multivariate statistical methods have been applied across the gamut of reservoir parameters for these wells to gain further insights into critical success factors and mechanisms. Response variables were established (producing time to reach various watercut thresholds) to gauge well performance. Principal component, factor, and multiple regression analyses were applied to independent reservoir parameters for a population of 20 horizontal wells placed in the target zone. These parameters included zone thickness, standoff from fluid contacts, vertical permeability contrast, thickness of low-permeability interval, reservoir contact, net/gross ratio, completion design, extent of fracturing, zone porosity, proximity to injectors, and trajectory orientation. Multivariate analysis conclusively demonstrated that the principal factor governing well performance in the early period (up to three years) was the vertical permeability contrast or in other words, the extent to which a permeability baffle exists between the thin low-permeability zone and the underlying thick high-permeability zone. Other parameters may contribute to well performance beyond the 30% watercut threshold and will be addressed in a future paper. The findings from this study have been translated into Best Practices for exploiting thin oil zones and have been applied in further developing the thin oil zone in the subject field.
Many shale gas reservoirs have been previously thought of as source rocks, but the industry now finds these source rocks still contain large volumes of natural gas and liquids that can be produced using horizontal drilling and hydraulic fracturing. However, one of the most uncertain aspects of shale gas development is our ability to accurately forecast gas resources and shale gas development economics. The uncertainty of the problem begs for a probabilistic solution.
The objective of our work was to develop the data sets, methodology and tools to determine values of original gas in place (OGIP), technically recoverable resources (TRR), recovery factor (RF) and economic viability in highly uncertain and risky shale gas reservoirs. Existing approaches for determining values of TRR, such as the use of decline curves or even volumetric analyses, may not be reliable during early time because there may not be enough production history for decline curves to work well or the uncertainty in the reservoir properties may be too large for volumetric analyses to be useful.
To achieve our research objective, we developed a computer program, Unconventional Gas Resource Assessment System (UGRAS). In the program, we integrated Monte Carlo technique with an analytical reservoir simulator to estimate the original volume in place, predict production performance and estimate the fraction of TRR that are economically recoverable resources (ERR) for a variety of economic situations. We applied UGRAS to dry gas wells in the Barnett Shale and the Eagle Ford shale to determine the probabilistic distribution of their resource potential and economic viability. Based on our assumptions, the Eagle Ford shale in the dry gas portion of the play has more technically recoverable resources than the Barnett shale. However, the Eagle Ford shale is currently not as profitable as the Barnett shale because of the higher drilling costs in the Eagle Ford dry gas window.
We anticipate that the tools and methodologies developed in this work will be applicable to any shale gas reservoirs that have sufficient data available. These tools should ultimately be able to allow determination of technically and economically recoverable resources from shale gas reservoirs globally.