Distributed Acoustic Sensing (DAS) and Distributed Temperature Sensing (DTS) are novel surveillance technologies which are increasingly being used for in-well surveillance, including in injector wells. Some of the applications include injection profiling, acid-stimulation optimization, well-integrity monitoring, and fracturing diagnostics. Our goal here is to demonstrate how this can be applied to a particular type of water injectors that use dual injection lines to improve conformance by decomingling the injection between shallow and deeper reservoir targets. Specifically, annulus injection will be used to target the shallow reservoirs and tubing injection to target the deeper reservoirs. Several case studies will be presented from water injectors located in the South of the Sultanate of Oman. This required integrated evaluation combining data from surface meters, downhole gauges, open-hole formation evaluation, as well as DAS and DTS. It will be shown how the data was analyzed to assess the efficiency of the waterflood, to optimize the water injection operating envelope, to identify fracture initiation or plugging, but also to analyze the effectiveness of the well and completion design. Through its high sample rate and narrow spatial resolution, DAS is particularly effective at monitoring changes to injectivity in real-time. This is especially helpful for identifying the onset of fracture initiation and monitoring the growth in fracture height, which is difficult to achieve with other technologies. DTS warm-back analysis was also performed to complement the DAS interpretation and monitor changes in conformance with a deeper depth of investigation than DAS. The unique value of the fiber-optic sensing technology is that it enables the implementation of the dual annulus-tubing injection completion design without limiting surveillance capabilities, as conventional surveillance in this well design is either impractical, not feasible, or too costly.
A study was conducted to determine the optimum re-completion for an offshore Abu Dhabi well. The candidate well was completed as open hole in a complex carbonate reservoir with faults and fractures and suffering from rapid increases in water cut. To quantify the value of re-completing the well with ICDs completions, a dynamic simulation modeling and optimization workflow was applied. To evaluate the best completion design, the dynamic model was refined and history matched in the sector area of the well using multi-segmented well technique. The number of downhole compartments (sections between packers), location of packers and ICDs flow area were simultaneously optimized to determine the best completion options for the candidate well using an objective function that included both; the value of oil and the cost of water. The ICD flow area per compartment was reverse engineered into an appropriate number of ICD joints and set of nozzles as part of the completion design process. The workflow provided a quantitative method for choosing the most appropriate horizontal well completion and demonstrated significant value for installing downhole flow control devices. The presentation of the results in terms of oil gain and water reduction for the different objective functions provided a clear indication about the best completion options, depending on the cost or aversion for water production versus the value of oil.
A mature offshore Abu Dhabi oil field produces from a heterogeneous carbonate limestone reservoir with an important column of bottom aquifer. The reservoir heterogeneity is characterized by presence of kurst filled with fine materials at top section, conductive faults, fractures, and significant variation of other rock properties. Most of the main faults cross from the top of the oil column all away down to the bottom of the aquifer. Meanwhile, the field development mainly consisted of horizontal producers targeting the upper section of oil column with peripheral deviated water injectors to sustain reservoir pressure. Generally, producers start with high initial oil rates, but the early decline is steep due to rapid water cut increase resulting into lower well head pressure. Production profiles from PLT combined with FMI indicate that production and water influxes are contributing mainly from the fractured sections of the horizontal drain or through conductive faults. In the meantime, important matrix segments of horizontal drains present very low or no contribution to production. As a solution, surface bull heading and targeted zonal stimulations were performed, which yielded mixed results. This paper focuses on the analysis of the latest targeted matrix segment stimulation results, which include candidate selection background, description of stimulation method and operations, pre and post stimulation production performance analysis, analysis of main factors affecting carbonate matrix stimulation, and a summary of findings with overall implication to carbonate reservoir matrix stimulation.
A complex heterogeneous carbonate reservoir, located in the offshore of Abu Dhabi, started oil production in 1985. The initial field development plan consisted of drilling crestal deviated producers and peripheral sea water injectors. As the reservoir is highly faulted and fractured with underlying high column of aquifer, water cut rapidly increased by channeling through faults system, reducing oil production. Consequently, the field development team decided to drill horizontal producers, and then later equip them with ESP. In the meantime, water injection rate was significantly curtailed due to uncertainty on injection benefit, which resulted in declining reservoir pressure, limiting production from some wells. In 2012, the team analyzed the historical production data to reassess water injection benefit. The study included areal analysis and correlations of reservoir pressure, voidage replacement ratio, logging data, production decline trends, bubble and saturation maps, and geologic data. The results indicated hydraulic communication between all reservoir areas, increased production decline rate with continuous reservoir pressure depletion due to low VRR and insufficient aquifer support, and poor pressure communication in some peripheral areas due to low reservoir quality resulting in lower transmissibility. Based on the analytical study results, reservoir simulation model was used to optimize water injection scheme, including optimum injector locations and optimum injection volume. Along the process, reservoir uncertainties were assessed through simulation sensitivities. The study results suggested maintaining the current peripheral water injection locations, increasing injection rate to minimize reservoir pressure depletion, working over the existing injectors/drilling new injectors to meet injection volume target, and carrying out further optimization after improved understanding of remaining geologic uncertainties. This reservoir management approach allows to continuously integrate reservoir geology and field dynamic data to reduce reservoir uncertainties and to optimize field development plan and operations.
For robust field development and reservoir management, it is essential to properly identify reservoir uncertainties. In this paper, we present case studies on the analysis of pressure transient data acquired in one of the offshore Abu Dhabi carbonate reservoirs. The complexity of the reservoir creates a number of uncertainties in the pressure transient behavior, making application of conventional analytical solutions insufficient to fully understand the characteristic of the reservoir fluid flow behavior.The field was first developed by drilling vertical/ deviated wells in 1980's and then horizontal sidetrack was conducted to enhance the well productivity and improve sweep efficiency since early 1990's. We reviewed the pressure transient test data throughout the field history including past surveys for original deviated holes. It was found that most tests in original vertical/ deviated holes were conducted under the oil-water two-phase flow due to the early water encroachment from the underlying thick aquifer. A close examination of these tests showed that wellbore effects associated with the oil-water two-phase flow significantly influenced the acquired pressure data masking reservoir responses. We also identified major static and dynamic uncertainties complicating the pressure transient analysis in this field. The major feature of the pressure transient behavior is a decreasing trend of the pressure derivative. Due to a number of uncertainties existing in this field, this behavior can imply more than one geological setting: thick active aquifer, faults, and vertical transmissibility reduction.In each pressure transient analysis, we consequently examined all the identified possible mechanisms adopting different fit-for-purpose analytical and numerical models. The fit-for-purpose modeling was found efficient to evaluate many uncertain factors including geological heterogeneities, multi-phase flow effects, and even the pressure interference from neighboring wells. This approach considering all the possible mechanisms enabled us to understand remaining reservoir uncertainties to be further investigated. In other words, this study is useful to identify major reservoir uncertainties and consider further reservoir surveillance to reduce such remaining uncertainties.
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