TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractWater production from gas producing wells characterized by low productivity and low reservoir pressure zones can prematurely kill wells, leading to a considerable loss in recoverable reserves. In some cases, mechanical techniques provide a viable solution for shutting off water production, although often, such a solution will create a restriction inside the well, limiting access to deeper reservoir layers. Even though chemical water shutoff chemicals and techniques are improving significantly, not many options are available to treat high temperature and low permeability reservoirs. It may prove difficult to squeeze cement slurries and different types of gels into such formations owing to constraints of particle sizes or fluid viscosity. It is a challenge to get a squeezable fluid into low-permeability reservoirs that will be effective in sealing the near-wellbore area and be able to withstand high differential pressure while producing. Another challenge is to determine a placement technique to prevent excess displacement of the treatment, to minimize further intervention into the well, to clean any residual treatment from the tubing, and to minimize water damage to highly sensitive producing layers. This paper presents successful case histories of treatments that were performed to shut off water producing layers characterized by low permeability. It describes innovative techniques that were developed for this special project. The treatments were placed using coiled tubing, and only one run was required to shut off the zones in question.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractWater production from gas producing wells characterized by low productivity and low reservoir pressure zones can prematurely kill wells, leading to a considerable loss in recoverable reserves. In some cases, mechanical techniques provide a viable solution for shutting off water production, although often, such a solution will create a restriction inside the well, limiting access to deeper reservoir layers. Even though chemical water shutoff chemicals and techniques are improving significantly, not many options are available to treat high temperature and low permeability reservoirs. It may prove difficult to squeeze cement slurries and different types of gels into such formations owing to constraints of particle sizes or fluid viscosity. It is a challenge to get a squeezable fluid into low-permeability reservoirs that will be effective in sealing the near-wellbore area and be able to withstand high differential pressure while producing. Another challenge is to determine a placement technique to prevent excess displacement of the treatment, to minimize further intervention into the well, to clean any residual treatment from the tubing, and to minimize water damage to highly sensitive producing layers. This paper presents successful case histories of treatments that were performed to shut off water producing layers characterized by low permeability. It describes innovative techniques that were developed for this special project. The treatments were placed using coiled tubing, and only one run was required to shut off the zones in question.
Natural gas is the primary source of energy in Bahrain, and the Khuff reservoir is the main supplier for this gas 4 . The Khuff reservoir, which was discovered in 1948, is composed of four limestone layers (K0, K1, K2, and K3) separated by tight limestone and anhydrite beds that can act as permeability buffers in some areas of the reservoir.In such a mature carbonate gas reservoir as the Khuff, managing and optimizing the performance of wells represents a challenge for the reservoir and production engineers because of the reservoir heterogeneity created by dissolution process which induced good porosity and permeability zones within a lower quality matrix rock; differential depletion, which occurs because reservoir heterogeneity creates a pressure difference between layers; and the commingle production as Khuff wells are completed comingled using either openhole or perforated completion.An integrated workflow applied to Khuff wells helped to understand the well performance and to optimize the workover activities. The process integrates the geological information, openhole data, multirate production logging test data, time-lapse corrosion logs, multilayer transient testing, and nodal analysis and is used to determine the remedial job that is required to achieve the most favorable well performance.The process was applied to one of the Khuff wells that was originally completed as K2 producer and then K1 and K0 were added in double casing using a small gun size because of completion limitations. The well performance after adding K1 and K0 was below expectation, and conclusion was made that the new perforations are not performing as been expected because of insufficient formation penetration. Thus, proposed remedial actions were to reperforate the K0 and K1 intervals using a bigger gun size and then stimulate them. However, before starting this costly operation, the integrated workflow process was used to assess the need for this workover operation. The integrated evaluation showed a different conclusion, which led to different workover plan, thus saving the cost of a more expensive workover operation.
A few years ago, following an extensive field study in North Kuwait, several wells were sidetracked and converted as horizontal openhole water injectors to support reservoir pressures as part of a secondary recovery plan. Production improvement was immediate, but injection rates soon started to decline and injection pressures were rising, eventually jeopardizing oil recovery. Conventional acid stimulation only led to short-lived improvements, and more elaborate methodologies rapidly became uneconomical. A new stimulation strategy was needed. In these carbonate reservoirs, marked, sustainable improvements in injectivity can only be obtained through accurate placement of stimulation fluid across the entire interval, away from high-intake zones that develop as a consequence of repeated blind acidizing practices. A real-time, pump-through downhole flow measurement tool was used with coiled tubing (CT) to profile the openhole sections and identify thief and tight zones prior to treatment. The tool enabled adaptation of the stimulation strategy and was then used to ensure proper fluid placement during the pumping stages. Both profiling and pumping were performed in just one trip. This innovative tool and its cost-effective workflow unlock a new level of operational efficiency. Whereas previous approaches required mobilization of additional equipment, the proposed methodology allows profiling horizontal sections and treating them in a single run with the same bottomhole assembly (BHA). For the water injectors presented in this study, this represented a saving of 3 days of operations and the associated logistics costs as compared to using logging tools and tractors for profiling. Moreover, real-time downhole flow monitoring with CT opens new avenues for treatment optimization, and ultimately, stimulation effectiveness. It allows for a better control of fluid resources and placement while the treatment is in progress. Flow sensors can be used to obtain the initial injection profile in lieu of distributed temperature sensing (DTS), which typically requires long acquisition times in water injectors. In this study, the wells treated with this approach showed a sustained 100% increase in injection rate, with the injection pressure dropping to nearly 0 psi. The volume of stimulation fluid needed was also lower than expected, yielding additional cost savings. By providing direct, real-time downhole flow measurement, this new tool brings acid stimulation execution to a new level of effectiveness, an advance necessary to the sustainability of many production enhancement projects in Kuwait. Furthermore, the use of this new monitoring capability is more cost-effective than conventional stimulation approaches that have proven either inefficient or detrimental to wells in the long run.
Completing horizontal wells with openhole sections or non-cemented liners is a common practice. This type of openhole wells is preferred to maximize reservoir productivity. Some questions that always come up for this type of wells are: will it be necessary to cleanup the mud and filtercake from the openhole section before or while starting production? Will the filtercake disperse and get removed while producing the well and applying drawdown to the formation? Will the remaining filtercake impair well productivity? The paper presents the case of a gas producing horizontal well in Indonesia completed with a perforated liner. The target reservoir is a clean sandstone reservoir. The horizontal drain is 1155 feet (ft) long. The reservoir permeability is ranging between 0.1 and 5 millidarcies (mD) An engineered oil-based mud was used as drill-in fluid to prevent any damage to the reservoir. A carbonate particle-based filtercake was used to create a thin and reliable filter cake. While drilling this well, it was believed that reservoir damage was minimized. It was also believed that there would be no need to cleanup the mud and filtercake left in the hole and that the well would cleanup by itself easily once it started producing. After disappointing production results from this well, zero production was achieved, a decision was taken to investigate the effect of the mud on well productivity, consecutive interventions were planned to remove one potential damage mechanism at a time and investigate the effect on well performance. Upon the completion of all the intervention steps, the well started to produce. A pressure buildup test performed one month after the intervention showed that the well was producing with a damage skin value of zero. The different interventions, the laboratory results and the effect of each taken step on well productivity are discussed in this paper. Overall results of the interventions will be shown and a complete solution for bringing new openhole horizontal wells into production will be proposed. Introduction The Tambora field lies in the swamp environment of the upper Mahakam delta, six miles south of Badak/Nilam. Tambora is now primarily a gas field, although there are small oil rims to the north (produced before 1990). Tambora field is operated by TOTAL E&P Indonesie as part of their operations in Indonesia's East Kalimantan region. In the same region, TOTAL is also operating Tunu, Peciko, Bekapai, Handil and Sisi-Nubi fields. TOTAL is the major contributor for gas production in the region. Fig. 1 shows a map of the different fields location. The Tambora field produces from a series of interbedded deltaic sandstones, shales, coals and locally limestones. These formations are classified into four main zones: D, E, F and G. The G reservoir is characterized by its low permeability. Its productivity while produced through vertical wells is low and deemed not satisfactory. For this reason, development of this field through horizontal openhole drains is necessary to achieve acceptable level of production. Openhole completed reservoirs will lead to higher productivity index but usually damage due to drilling mud is a concern. During the recent years, mud systems evolution was remarkable. The objectives are to achieve:Very low leakoff to the reservoir by the design of optimized filtercake, this will prevent the reservoir damage due to mud invasion,Easy removal of the filtercake by applying a minimum drawdown to the formation. This will enable maximum productivity from the reservoir without any potential need for a stimulation intervention.
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