Open hole screen completions are efficient in installation and reliable in use if designed properly. The major weakness of Open Hole screen completions have been lack of zonal isolation. An Open Hole Zonal Isolation packer has been developed and installed in 5 wells with up to 14 packers per well. No downtime, operational time or installation failures were experienced. The packer construction is based on the swelling properties of rubbers with crude oil. Introduction The lack of reliable open hole annular sealing has limited the application of open hole screen completion solutions. No zonal isolation means that zones can not be independently inflow controlled. This limits the use of screen completions where there are potential of water or gas inflow problems. Smart well systems, inflow control devises, multilaterals or inflow controlling interventions may be used when effective annular isolation exist. Previous technology has been inflatable elements, (External Casing Packers (ECP)) or gravel pack (GP). The ECPs are activated by pumping from surface through a tool on the end of the service string and into the inflatable element. A project was initiated between Easy Well Solutions and Norsk Hydro to develop a packer that did not have the same inherent risk. An oil swelling packer was successfully developed and used in the field. The Grane field The Swell packer was developed for the Grane field. The reservoir pressure and temperature is low and consists of unconsolidated sandstone. There are no pressure barriers within the reservoir, but some internal shale has been seen. The fluid is relatively heavy and viscous oil which forms stable emulsions with the formation water. A long term well test in 1996 revealed that an open hole completion with sand screens will give extensive annular flow and possible screen plugging. ECPs run in the well caused operational problems and did not give the desired effect as 2 of 5 failed to set. A quantitative risk assessment (QRA) was done for the pre-drill wells on Grane identifying ECPs as the single most critical element in the well completion design. The criticality was linked both to a high operational risk and the possibility of plugging the screens during production in case they fail. Hence developing a new packer with higher reliability and lower operational risk has had high focus in the Grane license.
In the challenging North Slope operating environment, use of innovative production equipment has provided solutions to zonal isolation and packer integrity problems in viscous oil reservoirs. Operators have employed new tools and technology utilizing expandable rubber materials to manage annular fluid flow, control solids/shale production, and achieve zonal isolation in wells where high costs, shallow depths, and long step-outs create unique completion challenges. The new technology is allowing once bypassed zones to be added to existing developments, and making future developments more economically viable. The new design approach involves installing swelling rubber packer (SRP) technology as part of the completion. This technology is based on specially designed swelling properties of rubber in crude or mineral oil based mud (MOBM) to expand and seal the annulus. The paper describes one operator's use of as many as 17 devices in a tri-lateral horizontal undulating well to manage annular flow and minimize shale/solids production. The successful application of this technology has allowed shale interbedding to be effectively isolated behind blank pipe, thus allowing an additional zone to be added to the existing development. To date the technology has been applied to eleven wells, improving production assurance. Another major operator on the North Slope has used the technology to isolate potentially conductive fault crossings along the lateral and inadvertent zonal crossings while kicking off from the parent bore. Multiple packers have been run in single laterals to achieve the desired isolation without noticeable effects on liner running drag. Recent density caliper data shows significantly more washout than previously envisioned, increasing the desire to manage annular flow. Development and application of this SRP technology is detailed in the paper, including documentation of improved efficiencies as a result of its use. The paper will also discuss field operations, installation, and unique considerations associated with design and installation in viscous oil environments. Introduction On the North Slope of Alaska, it has been estimated that between 20–25 billion barrels OOIP of viscous oil are contained within shallow, regionally extensive sands. [1,2,3,4,5,6](Figure 1) To date, development of these viscous oil sands has been deferred in favor ofthe warmer, less viscous oil that lies below. The presence of the highly viscous oil in the shallow sands results from oil biodegradation and low reservoir temperatures due to the extreme northern latitude, the presence of 1,800 feet of permafrost, and its relatively shallow burial depth.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractOpen hole screen completions are efficient in installation and reliable in use if designed properly. The major weakness of Open Hole screen completions have been lack of zonal isolation. An Open Hole Zonal Isolation packer has been developed and installed in 5 wells with up to 14 packers per well. No downtime, operational time or installation failures were experienced. The packer construction is based on the swelling properties of rubbers with crude oil.
A system has been developed and tested that reduces the production from zones producing high water cut in open hole screen completions. By use of flotation balls with neutral density in formation water, the system automatically reduces a nozzle area on each joint with increasing water cut. The oil selective inflow control system (OS) is used to reduce flow from zones that significantly contribute to the water cut in a well. A reservoir simulation tool has been configured to incorporate the OS functionality. Introduction Most oil wells that penetrate more than one reservoir zone or penetrate long reservoir intervals may benefit from inflow control to limit water and gas production. Sliding sleeves or smart well systems are expensive and time consuming to install and are proven to pose reliability challenges, flow area constraints and other limitations. Inflow control devices (ICD) (passive chokes or capillary flow paths) have been used in long horizontal wells primarily in the Norsk Hydro Troll Field with success to delay gas coning. By sizing the chokes, the sandface pressure along the wellbore is made more uniform. This results in better areal drainage. ICDs were in the Grane field simulated with ECLIPSE and NETool reservoir simulation software, but did not provide gains in production rates or ultimate recovery to increase the NPV of the field. This is mainly decided by high oil viscosity and the larger importance of water influxes in Grane, than on Troll. It was decided to study the possibilities and impact of an Oil Selective inflow control system (OS). A test and simulation program was set up between EWS and Norsk Hydro to verify the functionality and operational limitations for an OS in the Grane field. The Grane Field Grane is operated by Norsk Hydro and lies in the southern part of the North Sea, Norwegian Sector. The reservoir has excellent reservoir properties.
Heavy oil reservoirs generally suffer from low recovery factors and high operating cost. To optimize recovery and minimize operating cost, experience and insights should be collected to enable shift changes in development costs. Different options for enabling these developments are proven or suggested in this paper. Horizontal or deviated wells are considered the base case. Heavy oil reservoirs often suffer from:Unconsolidation and sand production due to immature rockemulsions and annular solids transport causing plugging of screens and sand control failuresserious water or steam breakthrough due to mobility ratios preferentially producing unintended fluidsmarginal production rates due to high viscosity and low reservoir pressure. In addition, steam floods are challenged by high completion costs due to extreme temperatures encountered, and high energy consumption due to production of high temperature fluids. All of these factors contribute to reduced ultimate recovery and well life. The paper describes case studies and concepts for the optimization of such heavy oil production systems, including uncemented completions which are very often beneficial to minimize well cost, minimize sand control challenges and maximize recovery. Introduction The three systems for optimizing heavy oil production discussed below include:Short swelling rubber packers (SRPs) to arrest annular solids transportZonal isolation straddles for water shutoff applicationsDownhole low-cost autonomous inflow control systems including steam control Heavy oil and annular flow management With viscous crude, water production can create emulsions which can carry particles very easily in an annulus. The transport of solids and permanent or reversible plugging may cause screen erosion and thereby loss of sand control. It may also cause severe productivity and recovery loss. The emulsion may be stable as a water-in-oil emulsion, until the water cut reaches a level where the the water becomes the outside phase and the viscosity is in a third stage. To manage annular flow, the following important factors are nescessary to prevent the formation and promote breaking of emulsions: Water production. If water can be shut off or separated to limited intervals, no emulsion will be created. Oil viscosity . The oil viscosity is generally not affected unless thermal recovery methods or gas injection methods are used. Even then, the crude oil viscosity generally still remains in the range where emulsions are likely to be formed. Flow velocity. With high annular flow, the velocity stabilizes the droplets and creates a homogenous emulsion. The annular flow velocity can be reduced by compartmentalizing the reservoir section into smaller " independent" sections. Particles. With small particles from the sand body or interbedding shale sections, the droplets and the emulsion will be stabilized in a similar way as oil based muds are stabilized. The risk of the formation particles being released and mobilized can be minimized by reduced flow velocity. Residence time. A longer residence time in a given annulus will increase separation, i.e, .break the emulsion. Separation times at reservoir conditions are generally far shorter than at surface conditions.due to the temperature and higher gas saturation downhole.
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