A 3600 m deep well has been used to conduct large water injection tests in the Rhine Graben. The total volume injected during the fall 1993 reconnaissance program reached 44000 m 3 . Induced seismicity was monitored with both a downhole and a surface seismic network. About 20000 events have been recorded by the downhole tools and 165 events with the surface network. The largest observed magnitude reached 1.9, as determined from signal duration observed on the surface network. Borehole televiewer observations show that some slip events were larger than 4 cm at the borehole wall, a value much larger than the slip motion associated with microseismic events, as evaluated from events' magnitude. It is concluded that these observed slip events were aseismic. This implies that induced seismicity is not a good marker for the efficiency of this hydraulic stimulation. It only helps to identify zones of high pore pressure during injection.

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In a high number of deepwater fields, water injector and producer wells are being drilled with synthetic or oil-based drilling fluid (SBM or OBM). The filter cake and drilling fluids residue left on all of the well surfaces after the drilling phase is a water-impermeable layer. If not removed, they will compromise project objectives. To avoid excessive operating costs and to remove near-wellbore damage, a quick and efficient removal of SBM or OBM with properly-designed clean-up fluids, such as microemulsion fluids, is required. Properly designed microemulsion spacer fluid formulations can be used to displace the SBM or OBM to a water-based fluid and completely water-wet all the surfaces in less than one circulation. The displacement fluids are formulated with customized surfactant blends (CSB) that exhibit equal affinity for the oil and water phases. They promote a very thorough microemulsification of the oil residue from the SBM or OBM during the displacement operation resulting in an aqueous external phase at the end of the process. The microemulsion displacement fluids are formulated to: (a) prevent viscous sludge at the fluids interface; (b) remove all of the oil from the surfaces; and (c) make the wellbore surfaces and near- wellbore region water-wet. In addition to spacer fluid formulations, customized microemulsion fluids can remediate wells and increase water injectivity and well productivity. These fluids contain a customized surfactant blend (CSB), a small amount of acid, and an optional co-surfactant. They form an in-situ microemulsion and produce a uniform wellbore cleanup in horizontal and highly-deviated open-hole wells. Customized microemulsion fluids are able to cleanup in a broad range of temperature, density, and salinity. They restore the water-wet condition of the rock and increase injectivity or productivity of the wells. This paper presents laboratory evaluations and field data of treatment fluids for wellbore displacement and near-wellbore cleanup based on the microemulsification mechanism. Data from systematic evaluation tests performed prior to field application (e.g. interfacial tension, detergency tests, fluids compatibility, filter cake removal and regain permeability) demonstrates performance results that were beyond the capabilities of conventional treatments. Based on the key performance indicators (turbidity of completion brine, volume used and resulting cleanliness of tools), displacement of SBM or OBM with microemulsion cleaners in deepwater applications was achieved in one circulation during the wellbore displacement process. Successful removal of SBM or OBM in the near wellbore region is evidenced by comparing predicted and achieved injection and production rates.

Peciko is one of the giant gas fields located in the Mahakam area, Indonesia, operated by Total E&P Indonesie. Since start up in December 1999, until May 2012, the average wellhead pressure and temperature of its wells have decreased from 150 barg to 20 barg and from 95 °C to 60 °C, respectively, while the average water/gas ratio (WGR) has increased from approximately 2.5 to 20.5 bbl/MMscf. These dramatic shifts of production parameter and borehole environment are believed to be the main factor of the increasing rate of scale deposition in significant number of its wells in the last few years. The nature of the scale encountered is mainly calcium carbonate and iron carbonate. Reviews have been carried to better understand the phenomena of scale formation in the field and to formulate the optimum solutions in overcoming it. Guidelines have been established to facilitate early detection or prediction of scaling, which includes routine water analysis, periodic check of tubing clearance, and running multifinger caliper in the well. Numerous attempts of removing the scale have been tried, with mechanical and/or chemical techniques, from light intervention using slick line unit, until semi-heavy intervention with coiled tubing unit (CTU). Several successful results have been observed, to some extent. Calcium carbonate scale showed to be relatively easy to remove, but the presence of iron carbonate imposes more challenge and complication. The milling operation, in particular, has been improved to minimize the negative effect of liquid circulation in sensitive wells, i.e. evolving from CTU milling using brine, to CTU milling using nitrified base oil, to electric line milling without liquid circulation. The guidelines, lessons learned, and the foreseen solutions are considered as the key elements of scale management in the field, and will be described further in the paper.

Handil field is a mature oilfield located in East Kalimantan Indonesia, operated by TOTAL E&P Indonesie (TEPI). By 2012, there were several wells completed with Gravel Pack completions that were producing sand during production phase. This condition created a hydrocarbon production limitation around 3700 bopd from three oil wells. TEPI were looking at technical solutions to improve well performance. Within the solution options that exist, chemical treatments - that consolidate the near wellbore area - can be a viable alternative for a number of completion types. Chemical sand consolidation can give a formation additional residual strength. This can enhance a maximum sand free rate (MSFR). One chemical treatment developed is environmentally acceptable by North Sea standards and simple to deploy by in a ‘one pass’ pumping operation. Looking at the completion type and complication during sand control remediation pumping, this chemical was finally chosen. The simpler deployment operation, since there is no overflush, induces less risk during pumping the treatment. The active chemical reacts with connate water in the near well bore area and forms a polymerized network around and between the sand grains. This network imparts additional residual strength allowing the near well bore formation to withstand greater drawdown and fluid flow. This paper discusses the experiences of TEPI with respect to using the organo-silane based chemical treatment in Handil field, Indonesia. A well intervention campaign treats a number of production zones which were treated separately by sliding sleeve door (SSD) selection. To ensure liquid cleanliness prior injection into formation, the use of coiled tubing was required and the treatment programs were adjusted from standard designs to accommodate this. Most of the operation performed resulted in an increase of the MSFR (leading to production increase). One job result however was not as per expectation. The lessons learnt from these treatments and improvements in candidate selection will be discussed here. This first coiled tubing application of the organo-silane based chemistry and the need to manage multiple small batches of the water sensitive treatment in a humid and wet environment were challenges to overcome.