Stimulation of a Deep Sour Gas Reservoir Using Gelled Acid
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Geothermal reservoirs differ significantly from their hydrocarbon counterparts and so do their remedial treatments. Typically these reservoirs are naturally fractured volcanic sandstones with varying mineralogy found over a wide temperature range. Often the zones of low permeability limit the efficient recovery of heat from these reservoirs. The low permeability could either be inherent or induced by damages occurred while drilling and/or production phases. The drilling phase often experience significant fluid losses, which cool the well and near wellbore zone from the high bottom hole static temperature to the moderate levels that make drilling, cementing and completion of these wells possible. The loss of cuttings and drilling mud to permeable formations and/ or fractures is a major source of damage. Other potential damages occur when the well is put on production. As such it is common for these wells to experience a decline in production owing to such formation impairments. Permeability in these zones may be enhanced through methods of well stimulation such as acidizing and high-rate injection. Such practices usually employing mixtures of hydrochloric and hydrofluoric acids in various concentrations, have widely been used worldwide but performance has been somewhat spotty and unpredictable. Also owing to the typical difficult locations of geothermal sites, there have been concerns about the logistical and QHSE aspects while planning conventional treatments. A successful application of a unique acidizing system & other techniques into geothermal wells in Indonesia is presented in this paper. This acid system involves controlled in-situ generation of HF acids based on organo phosphonic acid chemistry. It provides unique advantages in geothermal application in terms of both the enhanced well performance and rightly addressing all the logistics/QHSE issues discussed above. The last treatment with this system resulted in almost 3 folds increase in productivity of well. 1. Introduction Make up steam supply production wells are now being drilled in the Salak geothermal field, a liquid dominated geothermal resource operated by Chevron in Indonesia. Well Awi 8–7, Awi 10–3 and Awi 8–8 are production wells drilled in the 2004 make up steam supply drilling program. After completion, those wells delivered steam at sub commercial steam flow rates at system operating pressures. A comprehensive well stimulation program was planned and executed. The scope of the program included the diagnostic work to identify the causes, stimulation design to determine the most effective stimulation techniques, stimulation execution to carry out the stimulation job efficiently and safely, followed by evaluation to assess the result. Well Awi 8–7 was expected to produce 200 kph of low-gas- content steam. Despite promising indications, the initial steam flow rate from this well was below expectations. A completion test, consisting of pressure-temperature-spinner (PTS) survey, injectivity test, and pressure fall off (PFO) test was conducted to diagnose the problem. These tests were used to characterize the initial state of individual permeable zones to base a stimulation decision on. Injectivity and pressure fall-off (PFO) tests indicated that Awi 8–7 well had low injectivity index (II) and a positive skin. This data supported the fact that the well lost about 94,500 bbls of water-based mud from the drilling process has suggested the presence of the near-wellbore formation damage. Acid stimulation was designed and performed to recover the well. The acid was placed to the target zones via a 2″ coiled tubing. Post-acidizing well test analysis suggested the acid stimulation has successfully improved overall well characteristic. Total II increased from 2.56 to 6.55 kph/psi, permeability-thickness (kh) product increased from 252,000 to 403,000 md-ft, and the skin decreased from +2.2 to -1.2 Flow performance test after the acid job has confirmed a significant improvement of Awi 8–7 deliverability. This test confirmed the increase of maximum discharge pressure from 211 to 297 psig. The production output at stabilized flowing wellhead pressure increased from 51 to 160 kilo pounds per hour (kph) of steam.
Geothermal reservoirs differ significantly from their hydrocarbon counterparts and so do their remedial treatments. Typically these reservoirs are naturally fractured volcanic sandstones with varying mineralogy found over a wide temperature range. Often the zones of low permeability limit the efficient recovery of heat from these reservoirs. The low permeability could either be inherent or induced by damages occurred while drilling and/or production phases. The drilling phase often experience significant fluid losses, which cool the well and near wellbore zone from the high bottom hole static temperature to the moderate levels that make drilling, cementing and completion of these wells possible. The loss of cuttings and drilling mud to permeable formations and/ or fractures is a major source of damage. Other potential damages occur when the well is put on production. As such it is common for these wells to experience a decline in production owing to such formation impairments. Permeability in these zones may be enhanced through methods of well stimulation such as acidizing and high-rate injection. Such practices usually employing mixtures of hydrochloric and hydrofluoric acids in various concentrations, have widely been used worldwide but performance has been somewhat spotty and unpredictable. Also owing to the typical difficult locations of geothermal sites, there have been concerns about the logistical and QHSE aspects while planning conventional treatments. A successful application of a unique acidizing system & other techniques into geothermal wells in Indonesia is presented in this paper. This acid system involves controlled in-situ generation of HF acids based on organo phosphonic acid chemistry. It provides unique advantages in geothermal application in terms of both the enhanced well performance and rightly addressing all the logistics/QHSE issues discussed above. The last treatment with this system resulted in almost 3 folds increase in productivity of well. 1. Introduction Make up steam supply production wells are now being drilled in the Salak geothermal field, a liquid dominated geothermal resource operated by Chevron in Indonesia. Well Awi 8–7, Awi 10–3 and Awi 8–8 are production wells drilled in the 2004 make up steam supply drilling program. After completion, those wells delivered steam at sub commercial steam flow rates at system operating pressures. A comprehensive well stimulation program was planned and executed. The scope of the program included the diagnostic work to identify the causes, stimulation design to determine the most effective stimulation techniques, stimulation execution to carry out the stimulation job efficiently and safely, followed by evaluation to assess the result. Well Awi 8–7 was expected to produce 200 kph of low-gas- content steam. Despite promising indications, the initial steam flow rate from this well was below expectations. A completion test, consisting of pressure-temperature-spinner (PTS) survey, injectivity test, and pressure fall off (PFO) test was conducted to diagnose the problem. These tests were used to characterize the initial state of individual permeable zones to base a stimulation decision on. Injectivity and pressure fall-off (PFO) tests indicated that Awi 8–7 well had low injectivity index (II) and a positive skin. This data supported the fact that the well lost about 94,500 bbls of water-based mud from the drilling process has suggested the presence of the near-wellbore formation damage. Acid stimulation was designed and performed to recover the well. The acid was placed to the target zones via a 2″ coiled tubing. Post-acidizing well test analysis suggested the acid stimulation has successfully improved overall well characteristic. Total II increased from 2.56 to 6.55 kph/psi, permeability-thickness (kh) product increased from 252,000 to 403,000 md-ft, and the skin decreased from +2.2 to -1.2 Flow performance test after the acid job has confirmed a significant improvement of Awi 8–7 deliverability. This test confirmed the increase of maximum discharge pressure from 211 to 297 psig. The production output at stabilized flowing wellhead pressure increased from 51 to 160 kilo pounds per hour (kph) of steam.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractOil and gas assets in Shell Asia Pacific region formulate challenges and opportunities for improving well productivity through stimulation. Major factors limiting the activity in the past include:• Various types of reservoirs Confidence level of stimulation in Shell Asia Pacific region has been elevated. Lessons learnt and best practices established will be passed to future campaign. Stimulation is still a good means for increasing well productivity to get more oil at this high oil price time, but it has to be carried our properly.Although some success was achieved, current infrastructure for stimulation in the region still needs to be improved.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractFracture acidizing of carbonates has yielded increases in production in many areas of the world, but depending upon rock strength and reservoir closure pressure this response may be lower than expected. Also, as a result of rock strength and closure pressure, production may decline at a higher rate than after a proppant fracture treatment.Laboratory results are presented describing the effect on strength reduction of limestone and dolomite formation samples after exposure to various acid systems. Formation samples were dry, saturated with potassium chloride water or saturated with synthetic oil prior to testing. Samples were exposed to neat, emulsified, gelled and crosslinked 15 wt% hydrochloric acids and each exhibited a differing effect on rock strength reduction. In addition, production responses are presented and compared with regard to type of acid system used for stimulation.
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