An automated and compact multiphase flow meter (MPFM) tested offshore Saudi Arabia has accurately measured three-phase flow rates under existing field operating flow conditions. An extensive eight-month field test in the Safaniya field was conducted from October 1999 to June 2000 utilizing over 350 well tests under varying operating conditions. A meter was installed on an offshore test barge, so that individual wells could be tested in series with traditional test barge methods. For these trial tests, the total liquid rate ranged from 1300 to 12000 barrels per day, the GOR ranged from 150 to 350 SCF/STB and the water cut ranged from 0 to 50%. The results show that over 90% of the wells tested were within +/- 10% of test barge results for all liquid, oil and water cut measurements. While gas measurements were determined to be within +/- 15% in 75% of the wells tested. As a result of this favorable field test and other economic considerations, a multiphase flow meter is recommended for installation on all Safaniya Field existing offshore platforms. Project installation designs for the first five meters have been completed and plans are being made to install them beginning in early 2002. Introduction The Safaniya Field, which is the largest offshore oil field in the world, has a wide variety of offshore platforms. These platforms differ in physical size and vary from single well to eight-well configurations. For accurate reservoir management, each well is individually rate tested to monitor well performance and to provide data for field allocation and planning purposes. The wells are presently being tested by two barges, which are equipped with testing facilities. These barges are approaching obsolescence and require extensive maintenance to maintain the current testing schedule. In addition, numerous offshore platforms are located in areas that are inaccessible to the barges and cannot be easily tested. The barges are also prevented from testing wells approximately one third (1/3) of the time each year due to adverse weather conditions. Furthermore, well testing requirements for the Safaniya field are increasing dramatically due to higher water cuts as the field matures, more wells being drilled, and fluctuations in the field production requirements. As a result of the inefficiency and limitations of the test barges, a multi-phase flow meter was successfully field-tested as an alternative to the use of the test barges. Multiphase flow meters will provide the Safaniya field with more frequent tests and considerable economical savings in the long run. Meter Description The Fluenta multiphase meter 1900VI trial tested in Safaniya field is the latest multiphase flow meter produced by Roxar in Norway. This meter measures oil, gas and water rates without separation of the production stream, and calculates flow rates for actual and standard conditions. The multiphase meter determines oil, gas and water fractions from the capacitance, inductance readings and gamma densitometer measurements. Each component's velocity, or mass flow rate, is determined from cross correlation or venturi measurements. There are five main components to the MPFM:Capacitance sensor;Inductance sensor;Venturi;Gamma densitometer; andPressure and temperature sensors (see Fig. 1). A detailed discussion of each meter component and underlying operating principles can be obtained from the vendor, if interested.

A carbonate field in Saudi Arabia is undergoing major development requiring water injection wells to provide peripheral matrix water injection as pressure maintenance scheme to support oil production. The field is characterized by a tar mat zone, which potentially could isolate the oil reservoir from the planned pressure support and serve as a barrier for the water injection. Therefore, the injection wells were geosteered horizontally right above the tar " barrier?? into the transition zone between the heavy and lighter oil, which poses a challenge in assuring adequate pressure support to the producers, without leaving pockets of relatively high oil saturation behind the waterflood front. To address transmissibility uncertainty between producers and the injectors, long-term injection (LTI) pilot tests were designed utilizing one water injector and six observation wells to capture pressure signals. Building the surface facility to deliver the required test as planned was challenging, starting with the seawater as a source, to water treatment and ending with pump selection. This paper discusses the unique layout of the LTI surface equipment, a mini-plant by itself, and how operational challenges were overcome in the field. The authors highlight some operational issues related to the LTI test that had almost 90% efficiency from operating over 200 days and over 2 million barrels of injected filtered and treated seawater volume, as well as present valuable insights to demonstrate how a project of this scale was successfully executed and more value added to the development plans. The unique equipment layout comprised twin sea-submerged, skid-mounted electrical submersible pumps (ESPs), 6?? hoses, filtration unit, a chemical treatment unit, eight 500 bbl storage tanks, and a horizontal pumping system (HPS). The layout of the surface facility components, their performance and the importance of continuous water injection in addressing the test goals are discussed. The injection well performance was monitored by integrating Joshi's equation to Hall Plot and slope analyses to provide means of more meaningful use of injection pressure and rate data. The synergy of the mini-plant components coupled with engineered performance monitoring tools were enablers in this test design to help unlock more reserves. Overall, the test was a great tool to qualify field development plan assumptions, indicating that less powered water injectors than initially planned, are required Introduction Production from the carbonate field started several years ago from reservoir A with fluid and rock compressibilities being the primary drive mechanisms. Nearly 20 years later, production started from a lower reservoir Bb, and from reservoir Aa six years later. Due to low demand, it was subsequently shut-in. In all three reservoirs, (Aa, Ba and Bb) a continuous tar mat underlay the oil column and posed an uncertainty as to the extent it was sealing and effectively separating the oil column in the reservoirs from the underlying aquifer. Water injection was considered a priori since the assurance for an adequate natural water drive from the aquifer is low. With the present major development by means of peripheral matrix water injection as the planned pressure support mechanism, the tar mat created a potential challenge in assuring adequate pressure support for the field during production. Without an effective communication between the tar mat layer and the oil zone, with water flooding, a potential risk yet remains of leaving relatively high oil saturation pockets behind the flood front.

A carbonate field in Saudi Arabia is undergoing major development requiring water injection wells to provide peripheral matrix water injection as pressure maintenance to support oil production. The field is characterized by a tar mat zone, which potentially could isolate the oil reservoir from the planned pressure support and serve as a barrier for the water injection. Therefore, the injection wells were geosteered horizontally right above the tar "barrier" into the transition zone between the heavy and lighter oil, which poses a challenge in assuring adequate pressure support to the producers, without leaving pockets of relatively high oil saturation behind the waterflood front. To address transmissibility uncertainty between producers and the injectors, long-term injection (LTI) pilot tests were designed utilizing one water injector and six observation wells to capture pressure signals. Building the surface facility to deliver the required test as planned was challenging, starting with the seawater as a source, to the water treatment and ending with pump selection. This paper discusses the unique layout of the LTI surface equipment, a mini-plant by itself, and how operational challenges were overcome in the field. The authors highlight some operational issues related to the LTI test that had almost 90% efficiency from operating over 200 days and over 2 million barrels of injected filtered and treated seawater volume, as well as presents valuable insights to demonstrate how a project of this scale was successfully executed and more value added to the development plans. The unique equipment layout is composed of twin sea-submerged, skid-mounted electrical submersible pumps (ESPs), 6″ hoses, filtration unit, a chemical treatment unit, eight 500 bbl storage tanks, and a horizontal pumping system (HPS). The layout of the surface facility components, their performance and the importance of continuous water injection in addressing the test goals are discussed. The injection well performance was monitored by integrating Joshi’s equation to Hall Plot and slope analyses to pr ovide means of more meaningful use of injection pressure and rate data. The synergy of the mini-plant components coupled with engineered performance monitoring tools were enablers in this test design to help unlock more reserves. Overall, the test was a great tool to qualify field development plan assumptions, indicating that less powered water injectors than initially planned are required.