Haider, Bader Y.A. (Kuwait Oil Company) | Rachapudi, Rama Rao Venkata Subba (Kuwait Oil Company) | Al-Yahya, Mohammad (Kuwait Oil Company) | Al-Mutairi, Talal (Kuwait Oil Company) | Al Deyain, Khaled Waleed (Kuwait Oil Company)
Production from Artificially lifted (ESP) well depends on the performance of ESP and reservoir inflow. Realtime monitoring of ESP performance and reservoir productivity is essential for production optimization and this in turn will help in improving the ESP run life. Realtime Workflow was developed to track the ESP performance and well productivity using Realtime ESP sensor data. This workflow was automated by using real time data server and results were made available through Desk top application.
Realtime ESP performance information was used in regular well reviews to identify the problems with ESP performance, to investigate the opportunity for increasing the production. Further ESP real time data combined with well model analysis was used in addressing well problems.
This paper describes about the workflow design, automation and real field case implementation of optimization decisions. Ultimately, this workflow helped in extending the ESP run life and created a well performance monitoring system that eliminated the manual maintenance of the data .In Future, this workflow will be part of full field Digital oil field implementation.
The amount of tight formations petrophysical work conducted at present in horizontal wells and the examples available in the literature are limited to only those wells that have complete data sets. This is very important. But the reality is that in the vast majority of horizontal wells the data required for detailed analyses are quite scarce.
To try to alleviate this problem, a new method is presented for complete petrophysical evaluation based on information that can be extracted from drill cuttings in the absence of well logs. The cuttings data include porosity and permeability. The gamma ray (GR) and any other logs, if available, can help support the interpretation. However, the methodology is built strictly on data extracted from cuttings and can be used for horizontal, slanted and vertical wells. The method is illustrated with the use of a tight gas formation in the Deep Basin of the Western Canada Sedimentary Basin (WCSB). However, it also has direct application in the case of liquids.
The method is shown to be a powerful petrophysical tool as it allows quantitative evaluation of water saturation, pore throat aperture, capillary pressure, flow units, porosity (or cementation) exponent m, true formation resistivity, distance to a water table (if present), and to distinguish the contributions from viscous and diffusion-like flow in tight gas formations. The method further allows the construction of Pickett plots without previous availability of well logs. The method assumes the existence of intervals at irreducible water saturation, which is the case of many tight formations currently under exploitation.
It is concluded that drill cuttings are a powerful direct source of information that allows complete and practical evaluation of tight reservoirs where well logs are scarce. The uniqueness and practicality of this quantitative procedure is that it starts from only laboratory analysis of drill cuttings, something that has not been done in the past.
The Stybarrow Field is a moderately sized biodegraded 22° API oil accumulation reservoired in Early Cretaceous sandstones of the Macedon Formation in the Exmouth Sub-Basin, offshore Western Australia. The reservoir is comprised of excellent quality, poorly consolidated turbidite sandstones up to 20m thick. The field lies in approximately 800m of water and has been developed with five near-horizontal producers and three water injection wells. The Stybarrow development came online at an initial rate of 80,000BOPD in November 2007.
Due to the lack of significant aquifer support, water injection was planned from start-up for pressure maintenance. Acquisition of a variety of data types have enabled key subsurface challenges to be addressed both before and during production. Structural and stratigraphic complexities influence connectivity and therefore must be fully evaluated in order to achieve optimal sweep. A feasibility study concluded that Stybarrow would be a good candidate for 4D seismic monitoring. Two monitor surveys were acquired and, along with other reservoir surveillance techniques, have been used to refine the geological model.
The first monitor survey at Stybarrow was recorded in November 2008. The results of this survey were in agreement with prior 4D modelling and supported the drilling of a successful development well in the north of the field. A second monitor survey was recorded in May 2011, three and a half years after first oil and at 70% of expected ultimate recovery. This survey is currently being analysed to determine if sweep patterns have changed.
The 4D surveys have proven to be an important tool for understanding subsurface architecture and dynamic fluid-flow behaviour. The results of both 4D seismic surveys have provided significant contributions to understanding the dynamic behaviour within the reservoir to facilitate optimal reservoir management.
Fractal and power law distributions have been found in the past to be useful for modeling some reservoir properties following the assumptions of constant shape and self-similarity. This study shows, however, that pore throat apertures, fracture apertures, petrophysical and drill cuttings properties of unconventional formations are better matched with a variable shape distribution model (as opposed to constant shape). This permits better reservoir characterization and forecasting of reservoir performance.
Pore throat apertures, fracture apertures, petrophysical properties and drill cutting sizes from tight and shale reservoirs are shown to follow trends that match the variable shape distribution model (VSD) with coefficients of determination (R2) that are generally larger than 0.99. The good fit of the actual data with the VSD allows more rigorous characterization of these properties for use in mathematical models. Data that could not be described previously by a single equation can now be matched uniquely by the VSD. Examples are presented using data from conventional, tight and shale formations found in Canada, the United States, China, Mexico and Australia.
In addition, the study shows that the size of cuttings drilled in vertical and horizontal wells can also be matched with the VSD. This allows the use of drill cuttings, an important direct source of information, for quantitative evaluation of reservoir and rock mechanics properties. The results can be used for improved design of stimulation jobs including multi stage hydraulic fracturing in horizontal wells. This is important as the amount of information collected in horizontal wells drilled through out tight formations, including cores and well logs, is limited in most cases.
It is concluded that the VSD is a valuable tool that has significant potential for applications in conventional, low and ultra-low permeability formations and for evaluating distribution of rock properties at the micro and nano-scale.
Fractal geometry was introduced by Mandelbrot (1982) in his seminal work "The Fractal Geometry of Nature.?? He indicated that this type of geometry applies to many irregular objects in nature. Since then, fractals have been shown to be useful in many disciplines including geology, petroleum engineering, earthquakes, and economics to name a few. In geology, the approach has been used, for example, to evaluate the distribution of natural fractures in outcrops and reservoir rocks; also for evaluating stratigraphic units. In petroleum engineering, they have been used in efforts to capture the distribution of natural fractures for well test analysis. In the case of telluric movements, fractals have been used to evaluate very small to very large earthquakes. In economics, fractals have been used to analyze the distribution of income amongst populations. In the case of the oil and gas industry as a whole, fractal geometry has been used for estimating the spatial distribution of hydrocarbon accumulations (Barton and Scholz, 1995).
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.