Simultaneous Water And Gas (SWAG) injection has been implemented on the Siri Field on the Danish Continental Shelf and represents the first reported full field application of its kind in the North Sea. The associated produced gas is mixed with injection water at the wellhead, and injected as a two-phase mixture. The required total injection volume for voidage replacement is thus achieved with a simplified injection system, fewer wells and reduced gas recompression pressure requirements. Injection per well has typically been in the range 4,000–8,000 Sm3/day (25,000–50,000 bpd) water and 200,000 - 400,000 Sm3/day (7–14 Mscf/d) gas. Evaluation of alternative injection schemes identified SWAG as the optimum scenario for Siri. The choice reflects that:There is no established gas export infrastructure in the immediate area, Siri gas volumes alone are too small to warrant establishment of a system, and routine gas flaring is unacceptable. Reinjection is therefore required.Reservoir simulation studies indicate improved oil recovery (IOR) with combined gas and water injection as compared to pure water injection, apparently related to attic oil displacement, reduced residual oil saturation and better sweep efficiency.Continuous water injection from both injectors is required to maintain reservoir pressure. The SWAG concept fulfills all these requirements, representing a safe, economic and environmentally friendly development solution. Introduction The Siri Field, discovered late 1995, is located in the Danish Sector of the North Sea (Figure 1). Production started in March 1999 and injection in June the same year. Plateau oil production is 8,000 Sm3/d (50,000 bpd). The field has been developed with five producers and two SWAG injectors (one horizontal). The injectors are placed at the periphery of the reservoir in order to displace the oil to the central part of the field. Original plans called for 3 injectors, but this was reduced to 2 as the field was further delineated, making injection regularity and successful SWAG implementation even more critical. Siri's fairly isolated location meant that connection to an existing gas export infrastructure was not feasible. At the same time, the relatively small amounts of gas produced, and the rapidly falling gas rate, made it clearly uneconomical to develop a gas export solution for Siri alone. Gas flaring, or reinjection to a disposal site, were not environmentally acceptable alternatives, despite the limited volume involved. Reinjection of the gas to provide reservoir pressure support, better sweep and hence enhanced recovery, was the best overall solution. Reservoir Description The reservoir is characterized by a relatively low relief structure with oil zone thickness of up to 25m. The GOR is moderate, in the region of 100 Sm3/Sm3 (562 scf/bbl) and there is no initial gas cap. An 80–100 m thick underlying water zone gives some pressure support. Expected recoverable oil reserves have been estimated at 8.1 mill. Sm3 (51 mill. bbls), representing a recovery factor in excess of 35%. The reservoir rocks in Siri are deposited by sediment gravity flows in a deep marine environment. Hydrocarbons are found in the Heimdal sandstone of Late Paleocene age at approximately 2,070 mMSL. The formation consists of firm, fine to very fine-grained sandstone with a high glauconite content, cross-bedded to massive, reflecting deposition by turbidity currents. It is interbedded with several types of non-reservoir facies, such as mud clast conglomerates with a muddy sandstone matrix as well as thin shale and siltstone layers.

Injection of water and gas in combination, in most cases injected in an alternating scheme (WAG), is one of the most successful IOR methods applied in the North Sea. Simultaneous water and gas injection (SWAG) has so far gained less experience. Simulations show in general an IOR potential of the same magnitude as WAG. Field limitations may in some cases be in favor of SWAG injection. The main contributions to increased recovery come from improved sweep, oil swelling and reduced residual oil saturation. SWAG has recently been implemented on the Siri Field on the Danish Continental Shelf and represents the first reported full field application of its kind in the North Sea. The associated produced gas is mixed with injection water at the wellhead, and injected as a two-phase mixture. The Siri Field has performed SWAG injection from the production start in 1999. SWAG injection on Siri and experiences has previously been reported1. Reservoir studies predict field recovery improvements with combined water and gas injection. Injection of a two-phase mixture of water and gas represents some new challenges. One relates to injectivity. Combined water and gas injection may result in lower injectivity than for single-phase injection. Injectivity is therefore important in connection with practical implementation of SWAG. A discussion of injectivity behaviour and interpretation of Siri data will be presented. For the Siri Field, hydraulic fracturing of the injectors proved unavoidable due to unexpected low permeability in the injection zone. Above the fracturing pressure, the injectivity can be strongly dependent on the gas fraction of the injection mixture. Introduction The Siri Field, discovered late 1995, is located in the Danish Sector of the North Sea. Production started in March 1999 and injection in June the same year. Plateau oil production is 8000 Sm3/d. The reservoir is characterized by a relatively low relief structure with oil zone thickness up to 25m. The GOR is moderate, approximately 100 Sm3/Sm3 and there is no initial gas cap. An 80–100 m thick underlying water zone gives some pressure support. The field has been developed with five producers and two SWAG injectors (one horizontal). The injectors are placed at the periphery of the reservoir in order to displace the oil to the central part of the field. The SWAG solution with re-injection of gas is expected to give an IOR of up to 6 % over a water injection scheme. No former North Sea field applications of SWAG have been reported, but pilot tests performed in 1994 on Kuparuk River Field in Alaska2,3 have demonstrated the feasibility of SWAG injection. The relatively small amounts of gas produced, and the rapidly falling gas rate, made it uneconomical to develop a gas export solution for Siri alone. Re-injection of the gas to provide reservoir pressure support, better sweep and hence enhanced recovery, was the best overall solution. SWAG offered a solution whereby a changing mixture of injection fluids could be accommodated, with the flexibility to distribute the water or gas to the areas of the field deriving the most benefit. Full fluid injection volume could be maintained by combining produced gas and produced water, supplemented by seawater to the required total injection volume. Downhole pressure/temperature gauges have monitored conditions both during startup of gas and water injection as well as SWAG. Such measurements play an important part in well monitoring. The wellhead design pressure, compressors and injection pumps, the hydrostatic fluid column weight, and the near-well injectivity may restrict the actual injection rates for a SWAG injector. This paper discusses the different factors governing the actual injection rates. It includes a more detailed analysis of the near-well injectivity behavior on the Siri field observed in the first 8 months period after injection startup. Measured data are interpreted in terms of Eclipse simulations and an analytical injectivity model described below.

To be able to lubricate long perforating assemblies (guns) in horizontal wells, and to retrieve them without killing the well has always been attractive for many reasons, both from an operational point of view and to minimise formation damage. This paper describes a case study from the Siri Field where lubricating long gun assemblies against a tubing-retrievable downhole lubricator ball valve (DHLV) enabled running up to 1000 m of 3.5" perforation guns in two runs in a live well. This was performed without the use of a surface deployment system, and without exposing the tubing-retrievable surface controlled subsurface safety valve (TRSCSSV) to potential damage in the event of inadvertently dropping the perforation guns during completion. Use of this equipment gives also the added benefit of considerably reducing the equipment rigup heights for Siri in the future life of the field, after he jackup drilling rig has moved off location. Introduction The Siri Field, discovered in 1995, is located in the Danish Sector of the North Sea (Fig. 1). Production started in March 1999. The field is developed with five oil producers and two SWAG (Simultaneous Water And Gas) injectors, drilled using a jackup rig located over a wellhead tower. Well interventions will typically be rigless, requiring standalone equipment mounted on the wellhead tower. The horizontal producers have up to 1000 m perforations and it was desirable to perforate the entire interval underbalanced. Siri is expected to produce at relatively high water cuts for most of the field's life, and it is water-related problems which most likely will be the main reasons for future well interventions. Scale inhibition treatments at the rate of 1/well/year, reperforation and plugback of watered-out or gassed-out zones form the bulk of the anticipated workover program throughout field life. Coiled tubing would be the most likely intervention method. It is obviously desirable to perform these well interventions without killing the well. Platform design Siri is developed with a wellhead tower containing 12 well slots, at a centre-centre spacing of roughly 1,1m, connected to a jackup production platform. Headroom from the Xmas trees to the weather deck is only 2–2.5m. With future workovers in mind, ample deck space was included in the platform design, also workover fluid tanks and extra living accommodation to allow wireline, coiled tubing, pumping, snubbing and possibly coiled tubing drilling operations to be carried out at short notice from the platform, and without rig mobilisation. The wellhead tower weather deck itself measures roughly 12m×15m and is open to the sea on three sides. All rigup for well operations is above the deck. For coiled tubing operations with a deployment system, this could involve a 10–15m riser in addition to pressure control equipment. During completion operations with the drilling rig on location, support is available, but standalone operations could pose safety and logistical problems, requiring use of scaffolding or a workover derrick arrangement, and being highly weather-dependent. Use of long production logging tools would also lead to high rigups (Fig. 2).

Several companies have reported from 2% to 5% increase in oil production, and in some cases up to 10%, by a closer collaboration between onshore-based production optimization groups and offshore personnel. Several aspects have become apparent:shorten reaction time to implementation of optimization measures enables staff to take full and immediate advantage of opportunitiesthe work is manpower-intensive during the collaboration sessions, but ensures continuity and easy access to technical competenceengineering resources are already scarce, and there is a need to relieve staff of minor, routine tasks to enable attention to be focused on realtime issues requiring human expertiseincreased level of instrumentation complicates the work because it becomes increasingly difficult to utilize the available information to make better decisions Other industries in information rich and highly dynamic domains have over years utilized the capabilities provided by autonomous systems and their dominant implementation platform, software agents to improve the decision making process. Over the last few years in collaboration with an autonomous software platform vendor, StatoilHydro have tried to apply the experience from other domains on some of our core business processes, concentrating on improving the volume of produced hydrocarbons and the regularity of the production process. The work so far shows that in certain circumstances, autonomous systems can contribute to more effective production. In particular they enable more frequent adjustments in response to the actual well conditions. The main difference between the autonomous systems and more traditional automation is the ability to keep the human in control. In our latest attempt we have applied the concepts of variable and delegated autonomy from the domain of unmanned flight on our production process. Compared with more traditional automation, the concepts of delegated and variable autonomy introduce negotiation between different sub-systems and a much more adaptable human-machine interaction. Introduction The trend within the oil industry is towards increased instrumentation and the use of "smart" well technology for new developments. This has contributed to an increased information flow into the control room. The control room operators face new challenges with respect to their ability to utilise this information. From other industries, it is documented that increased information flow can contribute to information overload and lack of shared situation awareness between key stakeholders. In the control room of a large installation with 100 wells, where each well produces 15 different signals, 1500 different signals need to be processed at any given time. Humans are not able to process this flood of data rapidly and efficiently. One of the objectives of Integrated Operations is better utilization of technical experts, independent of location. For this vision to become reality, shared situation awareness between control room operators and remote experts is a prerequisite. Achieving the required level of situation awareness will be considerably assisted by an increased level of computerized support that is able to analyze complex data streams and transform the raw data input into events and derived recommendations for further analysis and action.

This paper presents the history matching of a clean-up operation of a long horizontal oil well at the Oselvar field in the North Sea using a commercial multiphase flow simulator. Data recorded during the actual clean-up is presented in the paper, and is compared with simulation results.Well clean-up is the process of flowing the drilling and completion fluids out of a new well, removing formation damage and filling the well with formation fluids. The role of upfront simulation of well clean-up is to optimize the operation and provide the basis for the operational procedure to be used onsite. Also, after the well clean-up has been carried out, the simulation tool may be used for history matching in order to gain understanding of what happened during the operation and assess the quality of the upfront simulation model.The data from the Oselvar clean-up operation revealed that the liquid flow rates at the initial choke size were significantly different from the rates predicted by the upfront simulations. Also, the time it took until no more drilling mud arrived topside was longer than expected. The data shows that the heel of the well was producing for several hours before there was any production from the toe of the well. This is attributed to the high initial productivity of the heel of the well, and to unexpected rheological behavior of the drilling mud. Constructing a transient downhole boundary condition based on the recorded data and on interpretation of petrophysical well data, a history matched simulation model was built that gave good agreement with the data.The work in this paper contributes to improved understanding of mud retention in wells during clean-up operations. The data and simulation results demonstrate why the modeling approach widely used in the industry may lead to a conservative estimate of the pressure margin before a well is killed, and an optimistic estimate of the time that is required to clean the well.