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.
The high decline rate observed in over pressured shale has attracted the attention of the industry, and better well management procedures for long term productivity improvement are still evolving. Operators are recognizing some benefit in controlled rate (controlled drawdown) production as one way of improving well performance for the wells in over pressured stress sensitive formations.
During uncontrolled rate production because of high drawdown, the permeability in stress sensitive shales decays faster because of increased stress. Often high initial gas rate is accompanied by high decline rate as the permeability reduction takes effect. In addition, proppant could also be produced back, crushed or embedded in the formation. However, controlled rate production minimizes the rate decline, albeit at reduced initial gas rate. Modelers resort to using different stress permeability decay coefficients for these two production strategies. Higher values are assigned to uncontrolled rate production to produce lower EUR. This approach, although convenient, requires different permeability versus stress tables depending on the production strategy.
Porosity and pore volume reduction in shales could be as high as 20 percent due to changes in net stress. The pore volume reduction provides in situ energy for gas recovery. The increased rate of permeability decay due to changing in situ stresses reduces the effectiveness of pressure support from pore volume reduction as fractures close under stress.. Controlled rate production strategy slows down permeability decay rate and this enables better use of pore volume energy. The pore volume consideration could provide additional gain to EUR for controlled rate.
Our analytical simulation model couples geomechanics permeability and porosity stress coefficients and evaluates well performance under moderate and low net stress sensitivity. Haynesville and Marcellus shales were evaluated. The importance of pore volume stress effect from the stand point of well performance evaluation and reservoir characterization is assessed.
The Pyrenees Development comprises three oil and gas fields: Ravensworth, Crosby and Stickle. The fields are located in production licenses WA-42-L and WA-43-L, offshore Western Australia, in the Exmouth Sub-basin and are operated by BHP Billiton (Fig. 1). Eighteen subsea wells, including 14 horizontal producers, 3 vertical water disposal wells and 1 gas injection well have been constructed to date and additional wells are planned for infill and to develop additional resources. First oil was achieved during February 2010 and production exceeded 50 million barrels in November 2011.
The Pyrenees fields are low relief, with oil columns of approximately 40 metres within excellent quality reservoirs of the Barrow Group. The 19° API crude has moderate viscosity, low gas / oil ratio (GOR), and a strong emulsion forming tendency which makes oil/water separation and accurate well test metering difficult. Early in the project design phase it was identified that the complex subsea gathering system and the need to reduce measurement uncertainties would dictate special attention to production measurement.
Subsea multiphase flow meters (MPFMs) were specified to meet the challenges of production optimization and allocation while at the same time minimizing production deferral for separator testing. Each oil producer is monitored by a dedicated MPFM. With 14 meters, Pyrenees is among the largest subsea MPFM installations worldwide.
This paper describes the process of MPFM qualification and commissioning together with their performance over 2 years in the field. We show how close cooperation between the Operator and MPFM Vendor has enabled quality rate measurements of emulsified production despite large changes in producing gas/oil ratio and water cut.
While the primary justification for Pyrenees subsea MPFMs was production allocation and optimization, interpretation of transient water cut and GOR data proved valuable for production and reservoir engineering applications. Examples of proactive reservoir and production management including optimizing drawdown of Inflow Control Device (ICD) equipped wells, optimizing well lineup and gas lift to commingled wells are presented.
This paper presents an overview of wet gas multiphase metering and a new meterdesign to meet future offshore challenges. The design introduces new microwaveelectronics, transmission as well as resonance measurements, a salinitymeasurement system, reduced PVT dependence and a new HP/HT design.
Building on the success of wet gas metering in accuracy and reliability, thenew meter increases operators' ability to detect the onset of formation waterproduction and accurately measure flow rates where an increasing amount ofliquid and water is present in the flow (due to gas wells produced over a widerrange of process conditions).
The new meter design will have an increased importance for subsea tiebacksapplications. While today's wet gas meters are well suited for subsea tiebacks,current subsea developments require longer horizontal production pipelines,where accurate and sensitive measurement of water is crucial to ensure flowassurance and maintain maximum production capacity of the pipeline.
Furthermore, the restrictive and remote nature of subsea fields means that thecosts for subsea interventions and periodic fluid sampling (PVT) are high. Thenew meter is more robust to changes in PVT (fluid composition) and reduces theneed for frequent fluid sampling.
The paper will describe the development and technology choices of the newinstrument and how it will meet future subsea field demands.
It will explain how the new microwave electronics provides more stable andaccurate measurements; how transmission and resonance measurements extend theoperating range to 80-100% GVF and 0-100% WLR; how two complementarytechnologies - a salinity probe for liquid film measurements at low GVF andFormation Water Detection Function software for droplets measurements at highGVF, provide the first complete salinity measurement system in wet gasapplications.
The paper will also show how multivariate analysis and new measurements enablethe meter to compensate automatically for changes in produced fluidcomposition.
The paper will be highly significant to oil and gas operators looking toincrease flow assurance and oil & gas production from wet gas fields andmeet the growing offshore challenges of varying process conditions,intervention costs, and subsea tie-backs.
Understanding the integrated performance of complex artificially lifted wells on not normally manned (NNM), offshore platforms without invasive techniques represents a challenge not only to minimizing operating costs but also to optimizing production and thereby maximizing value. Often the analysis of such problems is hindered by the complex interactions between identified production constraints and by a lack of operating data.
The Cliff Head oil field (offshore Western Australia) is developed with an innovative coiled-tubing deployed-electrical-submersible-pump (CT-ESP) artificial-lift system. This paper describes the process by which ESP and well data, in conjunction with a well-performance-modeling software, have been used as a powerful tool to diagnose well-performance issues and optimize production. Production trends were created on the basis of real-time production data to understand ESP performance. Individual-well models were created to identify potential causes of declining performance--in this case, the use of an ESP performance-limiting factor (PLF) indicating deteriorating ESP performance because of solids buildup.
On the basis of the model results, chemical soaks were implemented on two production wells to remove flow restrictions within and around the ESPs. The treatments increased the oil-production rates by 17 to 48%.
Following a debottlenecking study, reservoir simulation in combination with detailed ESP-performance analysis concluded that total-field-production improvements of up to 50% were possible. Consequently, the next phase of field development will install larger-capacity ESPs.
This paper outlines how field data and desktop tools were combined successfully to monitor and diagnose well-performance issues to deliver material production enhancements.
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 149472, "Analyzing Variable-Rate/-Pressure Data in Transient- Linear Flow in Unconventional Gas Reservoirs," by P. Liang, SPE, L. Mattar, SPE, and S. Moghadam, SPE, Fekete Associates, prepared for the 2011 Canadian Unconventional Resources Conference, Calgary, 15-17 November. The paper has not been peer reviewed.