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Biofilms of bacteria, indigenous to oil field produced water, were grown in square section, glass capillary flow cells at 45 degrees C. Initially, in situ image analysis microscopy revealed predominantly coccoid bacteria (length-to-width ratio measurements (l (c):w (c)) of bacterial cells gave a mean value of 1.1), while chemical measurements confirmed sulphate reduction and sulphide production. After nitrate ion addition at 100 and 80 mg/l, in the two repeat experiments respectively, the dominance of rod-shaped bacteria (mean l (c):w (c) = 2.8) was observed. This coincided with the occurrence of nitrate reduction in the treated flow cells. Beneficially, no significant increase in biofilm cover was observed after the addition of nitrate. The dominant culturable nitrate-reducing bacterium was Marinobacter aquaeolei. The l (c):w (c) ratio measured here concurs with previously reported cell dimensions for this organism. Several Marinobacter strains were also isolated from different oil fields in the North Sea where nitrate treatment has been applied to successfully treat reservoir souring, implying that this genus may play an important role in nitrate treatment.

Water Shut-Off in Oil Production Wells - Lessons from 12 Treatments. Abstract In the past few years water shut-off treatments in production wells have started to become accepted as part of standard well service work. The benefits from a successful treatment can be large and immediate; often the "pay-back" time for a water shut-off job is just a few months, weeks, or even days. This paper details the lessons learnt from BP's first twelve "modern" production well water shut-off treatments in Alaska and the North Sea, carried out over the last three years. Three types of treatment will be discussed:–Near well bore, total shut-off of an isolated zone. Here one entire section of well bore is being abandoned in order to allow production from other zones.–Injecting a relative permeability modifier, full well bore, into all perforated zones. In this case it may not be possible to identify the specific water producing zone, or there may be no barriers (such as shales) beyond the near well bore region to provide fluid control (of both the treating fluid and subsequent produced fluids).–Dual injection treatments. In this final category, a single, discrete, reservoir zone is targeted (for either total shut-off or relative permeability modification), but mechanical well bore control of fluid placement is not available. Detailed, example, case studies will be presented for each category of treatment, together with a discussion of how to apply the treatments to a range of reservoir conditions. Introduction Water Shut-Off (WSO) treatments in production wells are a routine part of standard well service work. We now use cement squeezes or mechanical isolation methods with high success rates for "straightforward" WSO targets. By contrast, the perception of chemical treatments such as polymer gels for WSO has been one of relatively high risk. Therefore we have tended to use gel-based methods as a final option (short of side-tracking the well) for WSO when standard methods are obviously inapplicable or have already been tried without success. These target wells have been complex, and some had mechanical limitations due to long-term shut-in or failed previous WSO attempts using plugs or cement. We have often been exploring new territory, and have had to consider many issues. Despite this, our experience since we restarted using gels in late 1993 has been very positive. The first six applications were all technical and economic successes. The conclusion so far is that with care a high success rate can be obtained with gel-based WSO, and this approach can often hit the parts other WSO methods cannot reach. As with any developing method, there are some potential problem areas. Some are chemistry-related, some are well-related and some reservoir-related. This paper deals with lessons learnt during design and application, and precautions and short-cuts we have found helpful. The lessons are drawn from 12 treatments, most of which (but not all) are mentioned specifically. These treatments were completed in collaboration with operating groups in BP Exploration and ARCO Alaska, Inc. There is still no comprehensive, how-to-be-safe manual as yet, but this at least brings together a partial check list. However, this is certainly not a comprehensive check list. In particular, other oil companies and service companies have been enjoying recent success with very different versions of the same gel system, and with different chemistries altogether. Our job designs are conservatively based on systems that we know well enough to control. Other options might well be simpler, cheaper or technically more robust than the ones we have used for some of our targets. As users and adapters, rather than inventors, we will undoubtedly pick up new designs, especially for some of the non-conventional well targets on the horizon. By discussing all we can think of in the way of job notes and alternative options we are aware that we may make the gel approach look complex and full of potential pit-falls. This comes from dealing with many very different intervention objectives. several chemical systems, and a vast range of well/reservoir conditions. The reality can be quick and easy. P. 415

A low concentration chemical treatment has been developed for pumping into a producer from surface to stop water production without harming hydrocarbon production. Matrix reservoirs are the primary target, though the upper permeability limit is not yet known. Numerical simulation has shown that while such a treatment would not be universal, many viable targets exist. Horizontal wells and multilaterals can make ideal targets, as would many vertical wells in heterogeneous formations and hydraulically fractured wells. Key performance targets were set for these chemical selective water-blocking systems (often called relative permeability modifiers). A dilute, water-dispersed system was favoured as treatment volumes were expected to be large in some cases. Because some of the chemical will enter valued oil/gas zones, the chemical must collapse to allow oil/gas to flow back through treated rock. A mechanism for this is described. To be of wide use, the chemical system should inhibit water production in reservoir rock with matrix permeabilities up to 10 Darcy, and at temperatures up to at least 110°C. Simulation indicated the minimum degree of water block required for selected targets. However, laboratory tests showed that blocks beyond 99.5% could be slow to clean up to hydrocarbon flow under available drawdown. This gave a performance target range. Well targets should always have appropriate reservoir stratigraphy, but it may not be possible to log the wells pre-treatment to check hydrocarbon/water inflow distribution. Therefore some "high-risk" treatments would fail because of lack of separate oil inflow, or absence of any flow barriers (such as shale) between water and remaining oil. A simple remediation treatment option was therefore required. Also, low toxicity and compatibility with production facilities were seen as non-negotiable properties. We describe the key molecular design parameters derived to give a polymer/crosslinker system with the performance demanded from simulation. Laboratory test results showing the required water/oil block performance and long term stability (at 100 °C) are presented. Field deployment designs including "rule of thumb" treatment volumes are described. The polymer and crosslinker were manufactured at full scale for trial application. Quality assurance tests of this unique "dancing-thin- gel" system are detailed. Results of several full-scale "calibration" field trials are presented. Lab-field correlation appears to be acceptably robust. Introduction Drilling and completion technology has advanced to permit economic development of more challenging reservoirs. Use of multilaterals, extended reach, horizontals, sand-screen/gravel packs, barehole, or sub-sea completions has become common. When these non-conventional wells cut water, they often still have significant production potential. However, access for remedial work such as Water Shut Off (WSO) interventions is difficult and expensive. Further, use of established WSO technologies such as straddles or coiled-tubing (CT) squeezes requires a Production Logging Test to gain knowledge of the water inflow point. Even then there is still a significant risk of failure. A PLT may show where the water enters the well. But it says little about whether reservoir shales are effective barriers to induced crossflow after the water has been shut off. For bullhead WSO, a PLT is not needed to help placement, though it might still help to select lower risk targets.

Waterflood conformance control due to reservoir heterogeneity is a common challenge to many oilfield developments. This paper describes the application at-scale of a thermally-activated polymer particle system (TAP) for improving waterflood sweep efficiency in the Prudhoe Bay field, Alaska. Since 2004, the technology has been successfully deployed 91 times in Prudhoe Bay Unit on the North Slope of Alaska as part of an approved Enhanced Oil Recovery (EOR) program. A total of 1.6 million gallons of chemical polymer particles have been injected into approximately half of the available waterflood patterns. Once the polymer particles activate deep in the reservoir, they provide resistance to water flow in the thief (swept) zones. The treatment design workflow applies a thermal model which accounts for the impact of the temperature distribution in the reservoir on activation of the polymer particles. Challenges associated with performance evaluation of the treatment program in a normal operational setting (as opposed to field trial) have been addressed, particularly in relation to interferences to interpretation resulting from the ongoing application of miscible gas EOR in the waterflood areas. Of the 44 treatments deployed between 2008 and 2012, 22 were sufficiently mature to have performance data which was not adversely impacted by interferences from well work, changes to operating conditions, or miscible gas breakthrough. So far, only one of the 22 patterns has not indicated an incremental oil response, while in two patterns the response had started too recently to be able to extrapolate the overall response magnitude. The analysis showed overall positive responses from the treatments that are competitive with other well work on cost/bbl and project economics. Results from this study provide insights on key controls on waterflood sweep improvements, and inform future candidate selection and optimization of treatment designs. The production performance analysis was corroborated by wellhead injectivity, repeat pressure fall-off tests, and reservoir modeling. This paper documents a good case history of waterflood sweep improvement.