TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractScale control in subsea horizontal wells is recognised as a particular technical and economic challenge, especially if effective chemical placement cannot be achieved through conventional bullhead squeeze treatments.When long horizontal or highly deviated wells produce from areas of high permeability contrast and high wellbore crossflow, coil tubing operations can often be the only manner in which effective chemical placement can be guaranteed. The costs associated with such treatments are extremely expensive and often prohibitive when compared with conventional bullhead operations. Such aspects were recognized as a particular risk for successful chemical treatments in the Draugen field, operated by Norske Shell. The Draugen field is located in the environmentally sensitive Haltenbank area of the Norwegian Continental Shelf, and produces oil from 6 horizontal (>1,000 ft.) wells completed with pre-packed resin screens to achieve effective sand exclusion. A moderate barium sulphate scaling potential was anticipated following sea water breakthrough requiring squeeze treatments. In order to improve chemical placement in this field and reduce the requirement for coil tubing interventions for squeeze treatment, work was initiated to investigate the potential use of viscosified fluids to improve downhole chemical placement.A range of viscosifying agents was selected following detailed literature review based upon the rheology that was expected to lead to improved chemical placement. This included common water control additives such as xanthan and HEC (hydroxyethylcellulose) biopolymers and formulated water in oil (WIO) or oil in water (OIW) emulsions. Various formulations were selected that would either remain stable (higher viscosity) or to break (to low viscosity) at reservoir temperature. It should be noted, however, that viscosities were selected far below those normally applied in water shut off or multi-stage chemical diversion treatments. A series of formation damage core flood experiments has been conducted using analogue cores to ensure that the various formulations were non damaging, allowing rapid recovery to pre-treatment effective oil permeability. In addition, more sophisticated core flooding equipment was designed to examine chemical placement and recovery in zones of different permeability.In summary, this paper presents a literature review describing the properties of different viscosifying agents and their potential applicability for improving bullhead scale inhibitor squeeze treatments. Core flood studies on viscosifying agents with selected rheological properties will then be presented to demonstrate the potential advantages of such applications for improved chemical placement by bullhead application in horizontal wells.

This paper examines the impact on scale squeeze life of water/scale inhibitor re-distribution during extended shut in periods for bullhead scale treatment in a high permeability reservoir. The Eclipse 100 reservoir simulator was used to examine water re-distribution (gravity slumping) during extended shut in periods for horizontal wells in the Draugen reservoir. The work shows that in certain cases involving long horizontal wells (>1000 ft) in high permeability sands (3–5D) with low vertical/horizontal permeability contrasts, extensive water re-distribution can occur during extended shut-in periods owing to density differences between the injected (aqueous) fluids and the formation fluids. Full field reservoir modelling was then carried out to identify candidate wells within the Draugen field which offered greatest potential for improved chemical placement based on these findings. Near wellbore placement modelling was then conducted to optimize squeeze return lifetimes using gravity re-distribution to improve placement deeper (lower) in the reservoir vs. convention scale squeeze design methods such as larger overflush. The work demonstrates that for selected cases, gravity re-distribution can be used to improve placement deeper (lower) in the near wellbore area. The modeling work also identifies limitations with the simple "radial" near wellbore models for such cases and identifies those wells in the Draugen field which would benefit from such treatments. An added benefit for low water cut wells was the potential to minimise post treatment lift issues associated with the injection of high volumes of water into the near wellbore for aqueous squeeze treatments, by allowing the injected aqueous treatment to sink away from the near wellbore area. New field treatments have therefore been designed based on the work described. The economic impact of the extended shut in times vs. improved squeeze treatments and deferred oil costs for this field case are also discussed following the field applications. Introduction Scale control in horizontal wells is recognised as a particular technical and economic challenge, especially if effective chemical placement cannot be achieved through conventional bullhead squeeze treatments.1–6 In addition to the challenges associated with overcoming permeability contrasts in reservoir formations fluid re-distribution due to reservoir crossflow effects can often reduce the potential to effectively place chemical into certain zones of a production well such that pump rates and / or viscosified fluids may be required in order to effect placement along the length of the well during the chemical injection stage. Once injected however further fluid re-distribution can occur which in many cases may have a detrimental impact on inhibitor retention and inhibitor placement as the bulk of the chemical treatment is removed from certain (higher pressure) zones and re-distributed to other (lower pressure) zones7. Although such fluid re-distribution is normally associated with reservoir crossflow, gravity effects are also known to cause fluid distribution and will be examined further in this paper. Gravity Slumping: For conventional aqueous chemical treatments in horizontal wells, gravity slumping due to density differences between the different fluids in the near wellbore area (lower density oil vs. higher density injected aqueous fluids) can lead to significant re-distribution during extended shut-in periods, especially when treatments are conducted at relatively low water cuts. Thus, fluid re-distribution may be expected to allow the inhibitor to contact more rock surface, be placed deeper (lower) in the formation and therefore result in improved squeeze lifetimes. This paper therefore describes a detailed evaluation of the impact of gravity slumping on the potential to re-distribute fluids in the near wellbore area and the impact this would have on scale inhibitor return concentrations.

The risk of reservoir souring is understood as one of the most serious effects of produced water reinjection (PWRI). Costly well backflows are traditionally used to monitor these effects. On Draugen (produced water 60°C, lean in carbon), a PWRI pilot is currently implementing nitrate to mitigate souring. Well backflows were not possible and another monitoring method for souring parameters was required. A souring mitigation cabinet (SMC) (two 1.4m columns with a 12 cm diameter, using a reservoir simulated sandstone medium), was designed. A side-stream of produced water was routed through the SMC over 3 months to allow typical reservoir biofilm development. Varying doses of nitrate (100, 80 and 50 mg per L) and nitrite (100mg per L) were then tested over a period of 15 days. Stoichiometric inhibition of SRB souring by nitrate (80 mg per L) and removal of background sulphide (100 mg per L) was exhibited. Nitrite (100 mg per L) exhibited short term stoichiometric mitigation. Control sulphide varied between 5 and 9 mg per L. 80 to 85% utilisation of nitrate and nitrite was shown. Dissolved organic carbon consumption was 28 and 29%, indicating no exacerbated carbon consumption in the test column. A two log10 difference in mesophilic SRB (30°C) and thermophilic SRB (60°C) was exhibited between the columns. NRB did not vary. The application of nitrate and nitrite stoichiometrically mitigated souring in the Draugen system and reduced the SRB population in the test column. This demonstrates the use of a SMC with a biofilm of the same properties as that developing in the near well area during PWRI. Such studies may reduce the requirement of backflows and give the opportunity to repeat trials of different mitigation strategies during operation and independent of PWRI. The SMC is being maintained on Draugen and is currently used to control mitigation effects on bulk produced water during PWRI. Introduction A produced water reinjection (PWRI) pilot project has commenced on Norske Shell's Draugen platform. The PWRI pilot is reinjecting approximately 50% of the produced water presently generated by the platform. PWRI as a means of produced water management has a well established history in the North Sea, particularly within the Norwegian Sector (1 - 5). However, the risks of increasing bacterial activity through PWRI are also well documented (5 - 8). The field specific risk at Draugen is discussed in internal Shell documentation and from previous work performed by Aquateam (9 - 14). Need for souring mitigation The Draugen produced water is lean in carbon (approximately 20 to 22 mg per L DOC) and as such, carbon is the major limiting nutrient for souring to occur (15). Based upon the volatile fatty acid (VFA) profile of the produced water, 30 - 32 mg/L C1 to C4, the maximum sulphide production is 16 to 17 mg per L (Figure 1).