Sand production has been a constraint to obtain maximized production rates for a number of years for several Statoil fields in the North Sea, due to issues related to: erosion potential not always easy to assess; safe operations: too many uncertainties related to increased sand production; and limited process handling capacity. Statoil has implemented the Acceptable Sand Rate (ASR), developed together with DNV, as a company strategy for increasing production rates by tolerating sand production within certain limits of maximum allowable sand volume, and maximum allowable erosion in the flow lines and the process system. Although these efforts have resulted in increased production, there is still a way to go to fully utilize the production potential. A key factor with respect to effective sand management is the collaboration and continuous communication among operators and suppliers, and the confidence and methodical approach that engineers and sand monitors' users should employ supported by a cross disciplinary effort. This paper will present the work carried out jointly by the operator and the suppliers through extensive lab work on the sand monitoring systems available today. The aim of the work is to explore the influence of piping geometry, sand characteristics and fluid/operational conditions on the sand monitors, in a controlled environment, in order to improve their implementation according to the ASR strategy. Instruments, test conditions, CFD analysis, results and conclusions will be described for both acoustic and erosion based monitoring devices.

Scale dissolvers have successfully been used to restore well productivity in two Statfjord Field wells suffering from scale induced formation damage. Combined with scale inhibitor treatment further production loss has been avoided. The dissolver efficiency towards BaSO4, and SrSO4, is strongly depending on high pH (pH> 9–10) in the treatment slug. Two different scale dissolvers have been tested, and are found to have equally good performance regarding dissolution capasities and effect on production. Well case histories and details about job design and production data before and after the treatments are documented. Combined scale dissolver and scale inhibitor squeeze treatment is implemented as the current scale treatment strategy for the Statfjord Field. Introduction The Upper and Lower Brent reservoirs in the Statfjord Field are developed with a row of sea water injectors, completed below the oil/water contact, to displace oil up structure to the east toward a row of oil producers near the crest of the structure. Key information about the Statfjord Field is listed in table 1.

Several wells in the Statfjord field are restricted from producing at their maximum production potential due to sand production. To optimise production and reservoir drainage, different sand control techniques have been used ranging from conventional cased hole gravel packs to through tubing gravel packs on live wells using coiled tubing. The gravel packed wells have made significant contribution to maintaining process capacity with the field moving into decline phase. Typical production increase after gravel packing has been about 2 – 4000 std m3/d. However, rapid plugging problems have been experienced after water breakthrough. Extensive scale dissolver and scale inhibitor treatments have been performed with varying success. Downhole video surveys have also been conducted to improve understanding of downhole well behaviour and well problems. The plugging problems experienced in the gravel packed wells have been difficult to predict and overcome. It is currently believed that the plugging is due to a combination of scale, migration of fines/particles and poorly filled perforation tunnels. Introduction The Statfjord Field is located in the North Sea on the Norway/UK boundary. The field is approximately 24 km long and 4 km wide and consists of the Upper and Lower Brent, Dunlin and Statfjord reservoirs. The Brent group is subdivided into five formations; Broom, Rannoch Etive Ness and Tarbert while the Statfjord formation is subdivided into three members, Raude, Eiriksson and Nansen (fig-1). The field has been developed with three concrete gravity base structure platforms. Each platform is a combined drilling and production platform with 42 slots divided between two wellhead areas. To date a total of 124 wells have been drilled, 10 of which are sidetracks. The oil production from the field is currently at 75.000 std m3/d with estimated total recoverable oil reserves at 620 × 106 std m3. Sand production has been a limiting factor preventing wells in both the Brent group and Statfjord formation from producing at maximum production potential. To minimise sand production, selective perforation of the strongest sandbeds, was therefore implemented as the production strategy. Until 1990 this strategy was considered sufficient to produce the platforms at process capacity. However, with rising water cut and the field moving into decline phase, it became increasingly important to produce wells at highest possible rates to fill process capacity and maximise profits. A sand control programme was therefore initiated in 1990. Sand Control Strategy. The main goal of the sand control programme was to gravel pack wells with a high oil production potential (PI = 500 – 2000 std m3/d/b) and low maximum sand free rate to maintain process capacity when other wells were shut in due to well activity, high watercut or high GOR. The Tarbert formation was selected as the ideal candidate for sand control measures since:–Sand production was most evident from wells in Tarbert.–The formation consisted of several less consolidated sandbeds with high oil production potential–Remaining reserves in this formation was estimated at 100 × 106 std m3 In the period from 1990 to 1995 a total of 8 wells were subjected to gravel packing:–4 gravel packs during workover and initial completion–2 gravel packs through tubing with the drilling rig–2 gravel packs through tubing on live wells using coiled tubing P. 653

Recent years have seen a profound change in the way the oil industry works. This change goes under the name of Integrated Operations, i-field, smart field and similar. The core to this change is a more effective use of data and competence irrespective of distance, organization and professional discipline. In Norway most operating assets have now made important steps towards implementing Integrated Operations in the form of collaboration between the offshore operations and the land based asset organization as their standard operating procedure. This implementation has changed the way of working within the assets in an irreversible manner. A next step in this change process could be to implement the IO philosophy to multi-asset technology support. Statoil has several multiasset support-centres in operation. In October 2008 a "Production Support Centre" – PSC – was launched to provide multidisciplinary support within production optimization to the assets. The establishment was based on a holistic view of production optimization – from the reservoir to the offtake - and hence comprised many different disciplines within productionand process technology in one support centre. The paper describes the philosophy behind establishing the Production Support Centre, how this philosophy has been implemented within the current business model of the company and the experience gained after one year of operation. The centre is involved in tasks ranging from online support to complex, multidisciplinary issues – "Task Force Support". The experience clearly indicates a need for such a centre in particular with regards to "Task Force Support". The paper will also include a discussion on how such centres contributes to improved value creation.

Calcium based brine has regularly been used during workover operations on naturally completed wells without any sign of formation damage. In gravel packed wells which have seen severe losses of Ca based brine production decline was observed.Fur some of the gravel packed wells the production decline occurred when bringing the well on production after completion, whilst in others, the loss in productivity occurred after sea water breakthrough. I In order to increase productivity and confirm the relationship between productivity decline and formation of CaS0 4 scale due to losses of completion brine, scale dissolver treatments were carried out.The use of dissolver chemicals resulted in mobilization and removal of several hundred kilograms of solids from the near wellbore area.A post-evaluation strategy to provide information about the nature, origin and location of scale was successfully implemented. More importantly, the dissolver treatments resulted in increased oil production.The findings and lessons learned have had several important implications for gravel pack completions and well treatments in Statoi!. 80