Subsea separation and produced water reinjection (PWRI) or discharge comprise an integral part of the subsea processing strategy that can bring many benefits, including economic, operational, and environmental, for the oil and gas industry. The importance of subsea separation and PWRI to economics has been demonstrated through work done by Statoil, which installed the world's first full-scale subsea separation system at its Tordis field in the North Sea. Statoil estimated that the system's installation would enable the company to achieve an additional total field oil recovery of 6%, which is equivalent to an extra 26 million bbl of oil. At a price of USD 50/bbl, this would lead to more than USD 1 billion of extra revenue. The most economic means of implementing subsea separation and PWRI or discharge operations is to use continuous online subsea water-quality measurement devices.
Opawale, A. O. (FMC Technologies) | Arreola, S. (FMC Technologies) | Ciprick, K. (FMC Technologies) | Ibouhouten, B. (FMC Technologies) | Kruijtzer, G. L. (FMC Technologies) | Verbeek, P. H. J. (FMC Technologies) | Akdim, M. R. (FMC Technologies)
Wellhead desanding may increase the productivity of an oil/gas well as it opens the opportunity to a minimized choked-back production. Utilizing a wellhead desanding system upstream of the choke valve, minimizes the risk of erosion of the downstream equipment as for example; valves piping, etc. In addition, better sand separation may be achieved at high pressures due to presence of dissolved gas in the crude oil. These benefits motivated the development of the Wellhead DeSander technology as a significant improvement to conventional cyclonic desanders, gravity-based sand traps and strainers.
The novel desander system utilizes a stationary non-rotating swirl element which removes sand particles from produced multiphase fluids driven by a centrifugal force. Separated sand particles are temporarily stored in an accumulator vessel designed with an automated system that detects the level of accumulated solids and initiates the flushing procedure. In this paper the development and qualification of the Wellhead DeSander technology will be extensively described.
Case studies describing flowback operations at shale plays across the US are presented. Field data is shown demonstrating the separation performance of the Wellhead DeSander at various operating conditions such as: fluid production rates in the range of 1,500 to 14,700 Barrels Per Day (BPD), produced sand concentration upto 5 % volumetric (V/V), heavy paraffinic hydrocarbon, Gas Volume Fraction (GVF) > 90 % and watercut upto 84 %. Separation performances of the Wellhead DeSander have been measured with and without an upstream conventional sand trap. Separation efficiencies upto 99 % have been achieved with the Wellhead DeSander technology. The Wellhead DeSander can provide substantial economic benefits such as reduced erosion of a process facility and minimized operating costs with sustained optimal well productivity when solids are produced.
A production choke is essential in regulating the pressure and flow rate of the produced hydrocarbon stream from a well in a field production system. Regulating the pressure and flow rate is necessary to achieve the production objectives of a field, which are to meet customer demand and optimally manage the reservoir over its life cycle. It is therefore important to have a means of effectively monitoring production choke performance to identify the onset of choke wear. Choke wear results from erosion of the choke due to impingement of particles carried in the produced hydrocarbon stream as it passes through the choke body. Choke wear increases the production rate and downstream pressure of a producing well, thereby upsetting the balance of the production system and resulting in ineffective field pressure management. Taking immediate action to replace a worn choke is therefore necessary to restore the production balance and achieve optimal pressure conservation of the production system. Choke performance monitoring is more critical for gas producing wells than oil producing wells because the velocity of gas is typically much higher than the velocity of oil, and consequently the risk and frequency of choke wear is much higher. Physical inspection of the production chokes to confirm wear for offshore gas wells is more laborious and time consuming due to the need to interrupt production, depressurize the flowline, decouple the choke body from the flowline, and ship the choke body onshore to the manufacturer's workshop for component inspections to confirm choke wear and, if necessary, choke replacement. A way to remotely monitor production choke performance and correctly detect choke wear for offshore gas wells without interrupting production is therefore operationally expedient, reduces exposure of personnel to unsafe rough sea conditions, and saves the cost of unnecessary physical choke inspections. The authors present a graphical method of monitoring the production rate and flowing tubing head pressure trends, with the choke size, of offshore high rate dry gas wells to detect choke wear using real-time production data. Examples of successful application of the method, which demonstrates that innovation can be simplification of processes, to detect choke wear and perform timely choke replacement are highlighted.
Wu, Xingru (University of Oklahoma) | Babatola, Feyidamilola (Linde Process Plants) | Jiang, Lei (Rhombus Energy Solutions) | Tolbert, Brandon T. (University of Oklahoma) | Liu, Junrong (China University of Petroleum (East China))
Subsea processing is an evolving technology in response to ultradeepwater hydrocarbon development and has the potential to become one of the most attractive methods in the oil industry to economically unlock hydrocarbon resources. The objective of this paper is to examine the features of subsea fluid-processing technologies and capabilities, and compare the advantages and disadvantages of different facility types. The advantage of subsea processing systems is that they allow fluids to be boosted from longer tieback distances. Constraints associated with subsea processing systems include operation efficiency, produced-waterand sand-handling capabilities, and the system's ability to handle hydrates/scale. In this paper, we reviewed the application of subsea systems in 12 deepwater fields and discussed the significance of each. Furthermore, future subsea-technology development and anticipated challenges are outlined in this paper. The significance of this study is to summarize the lessons learned from current available uses so that future decisions regarding the application of these subsea processing technologies can be made appropriately and efficiently.
Identifying, risking, and maintaining subsurface integrity is of critical importance to a variety of geologic subsurface operations including geothermal, oil and gas production (conventional, unconventional, fractured crystalline, heavy-oil fields), mining, natural gas storage, and sequestration of CO2 and hazardous waste. Predicting and mitigating out-of-zone fluid migration includes but goes beyond maintaining well integrity: it relies on technical understanding of top and fault seals, reservoir and overburden deformation, production/injection-induced stress changes, reservoir management, completions design and engineering, hydraulic fracturing/height containment, wastewater disposal, induced seismicity/fracture reactivation, and reservoir monitoring (e.g., geodetic and downhole measurement and interpretation). Subsurface integrity excludes surface facilities and spill response but includes regulations regarding subsurface activities.
In this paper we present and synthesize examples of subsurface containment loss from oil and gas fields that are documented in the open literature. We then discuss common risk areas or themes in subsurface containment geomechanics that are important to subsurface integrity and illustrate with some general examples how some of these could be investigated by using geomechanical models.
Containment of produced or injected fluids within their intended wellbores or geologic subsurface zones in oil and gas fields is widely recognized as a critical part of exploration and production (E&P) activities in conventional and unconventional plays and reservoirs. For example, it is a primary objective while drilling exploration, appraisal, development, and production wells. Maintaining the integrity of wellbores and subsurface geologic elements can potentially minimize drilling and operational risk. Effectively managing injection pressures, volumes, and rates of fluids in producing fields depends critically on adequately defining the geomechanical limits set by geologic elements such as overburden, caprock, top seals, faults, and evolving in situ stress states (including reservoir pressures). Characterization of the mechanical integrity of the subsurface relies upon obtaining baseline measurements including lithology, petrophysical and mechanical properties, pore pressure, and stress state that are best obtained during field appraisal and development, before production begins. Because the consequences of subsurface containment loss to an operator or partner can be significant, including both direct and indirect costs (e.g., clean-up cost, loss of production, and damage to reputation), even for small events, containment-related activities have assumed a larger share of enterprise risk as technologically more challenging fields are evaluated and placed into production .
Statoil is developing a subsea wet gas compression project on the Gullfaks in the North Sea. Steve Thurston, Chevron’s vice president of deepwater exploration and projects compares developing US Gulf of Mexico oil fields like Jack and St. Malo in 7,000 ft to the 1969 moon landing: “Except we are going to the moon every day!” It really is impressive to see how offshore and subsea technology have evolved over the years. Of the world’s current oil demand of approximately 93 million BOPD, some 27 million BOPD or 30% comes from offshore fields and the offshore contribution is expected to continue to grow according to Douglas-Westwood World Drilling & Production Market Forecast 2005-2021. The Norwegian Continental Shelf (NCS) is among the front-runners in subsea technology developments and applications.
Statoil is developing a subsea wet gas compression project on the Gullfaks in the North Sea. According to Statoil, it has more than 500 subsea wells and is the world’s largest operator in water depths greater than 100 m. The Troll-Oseberg Gas Injection subsea template installed in 1991 supplies gas subsea from Troll to Oseberg, 48 km away, making a gravity drainage recovery mechanism on Oseberg possible, resulting in a very high oil recovery factor. Through more than 150 multibranched subsea wells (two to six branches per well), individual Troll oil province development wells can connect with nearly 45,000 ft of productive reservoir. Subsea water separation and subsea reinjection units have been successfully used on the Troll oil and Tordis field developments.
Steve Thurston, Chevron’s vice president of deepwater exploration and projects compares developing US Gulf of Mexico oil fields like Jack and St. Malo in 7,000 ft to the 1969 moon landing: “Except we are going to the moon every day!” It really is impressive to see how offshore and subsea technology have evolved over the years. Of the world’s current oil demand of approximately 93 million BOPD, some 27 million BOPD or 30% comes from offshore fields and the offshore contribution is expected to continue to grow according to Douglas-Westwood World Drilling & Production Market Forecast 2005-2021.
The Norwegian Continental Shelf (NCS) is among the front-runners in subsea technology developments and applications. It is like a giant “subsea and offshore 2.0 laboratory” for the rest of the offshore world.
Efficient subsea gas compression is the next challenge that the industry must face to continue subsea development. When an offshore gas field is developed 100% by a subsea development and the pressure falls because of production, compression will be needed at some point to maintain the production rate. But, there is no platform to put it on—unless you build one. What about installing subsea compression and skipping the platform altogether? Is this even possible? I posed questions to Statoil’s chief engineer in subsea technology, Rune Mode Ramberg, regarding the latest subsea compression developments on the NCS.
Subsea Processing provides effective solutions to develop more and more challenging deepwater fields while maximizing oil recovery and optimizing the topsides.
By removing most of produced water at the seabed, a subsea liquid/liquid separation station allows to eliminate the need to transport high volumes of water from deepwater mature fields production and then to debottleneck existing topside facilities and to reduce the required water treatment surface equipment. Moreover, the low subsea separation pressure reducing the back pressure on the subsea wellhead allows for an increase in oil recovery, which is a key driver for such a system.
Dealing with the deepwater and high design pressures constraints, the SpoolSep, developed by Saipem for subsea gravity liquid-liquid separation, is made of several horizontal pipes working in parallel. The use of small and long diameter pipes for effective gravity separation of produced water combines robustness and efficiency. The pipes are designed as subsea spools which can be connected and disconnected individually for easy installation and maintenance.
A first test campaign was performed in 2013 on a purpose built multiphase flow loop operating with air, water, and model oils at ambient conditions using a transparent SpoolSep model made of four parallel Plexiglas pipes of 200mm ID and 18m length each. Different inlet conditions, such as flowrates, water cut, gas-volume factor, shear rate on water/oil mixtures, water residence time, and spool inclination, were tested to qualify the separator efficiency and operability, resulting in a whole flow visualisation inside the pipes.
Additional tests using several solid particle sizes were performed to qualify sand deposition and determine the limits of sand transport by fluid flowing inside a single spool.
The paper presents the main findings of the experimental tests that validated the multiphase flow distribution inside the spools, levels control and symmetry. Moreover, the validation of the SpoolSep design criteria regarding required separation performances is presented. Main observations and key findings on tests with sand are also described.
The presented work focused on the development and qualification of the fluid processing technology and does not make mention of any mechanical or structural design work.
Over the past 10 to 15 years subsea processing has been globally established as a market segment within the subsea development arena. Subsea processing is expected to be a growth platform for operators and for the service companies that are developing equipment and solutions for well processing and treatment at or below the seabed. The ultimate result of the All Subsea vision is the production of hydrocarbons from reservoir directly to market. Operators and service companies have high expectations for the profitability this business offers and share the All Subsea vision of future topside-less developments. This paper examines the realism of this All Subsea vision and discusses how the vision can be implemented, based on an analysis of the current state-of-the-art technology and the gaps and barriers that may jeopardize the realization of true subsea-to-market solutions. Developing products and systems with high development costs for a limited market requires a close cooperation between the suppliers and oil companies. The paper also reflects on the history of subsea processing, the market trends, and the way subsea processing technologies are adopted by the industry, seen from the authors' perspective and with their extensive experience in developing and delivering subsea processing solutions worldwide.