With the growing demand for oil production, and pressure maintenance for giant fields, more horizontal wells has been drilled as power water injectors and oil producers to increase the contact with the reservoirs. In M-field, many wells are drilled as mega-reach with a measured total depth up to 33,000 ft. This present a big challenge for coiled tubing intervention to reach TD and stimulate or perform logging. Even with the use of hydraulic tractors, CT Pipe Locks up before TD, and it has been difficult to understand the root cause as it is not possible to differentiate between a hydraulic tractor malfunction and downhole obstruction causing the CT to tag. Here in this paper we are going to illustrate the reach challenges, analysis performed on the un-anticipated lockups, and how could we utilize recent technologies in understanding the lockup occurrence, as well as quantifying the how can we improve the prejob tubing force model simulation to fine-tune well accessibility in real-time while on the job. With the implementation of the real-time tension-compression tool, it becomes possible to detect any malfunction of the hydraulic tractor. With the real-time reading of the tractor pull downhole, the coiled tubing force model simulation can be adjusted during the operating to match the real coiled tubing weight and have better estimation of the expected lockup depth. Real-time informed decisions can optimize the CT reach. Being in ultra heavy oil formation and barefoot completion, the following questions come to the scene: Are we tagging in tar? or it is just the excessive drag force that is causing an early lockup?; What if the tractor fails? and how to diagnose the failure?; Shall we use solvents? at what quantities if any?; Is it feasible to run more than once? or it is a challenge that we cannot overcome? All the above questions are answered in details in the paper with illustrated troubleshooting, and problem solving workflow that is aided by case studies, jobs results, and success stories from one of the biggest fields in the Middle East. Exploring more in this direction would successfully change the face of the tubing force model simulation algorithms and take the on-site operational excellence to a significantly advanced level.
Fiber optic enabled coiled tubing (FOECT) has been commonly used in qualitatively evaluating reservoir matrix chemical treatment in real time during the past couple of years. During this period, attempts of transforming qualitative evaluations to quantitative ones were made. The quantitative evaluation is based on two simultaneous criterions. The first one is a downhole pressure diagnostic plot (pressure transient analysis) created instantinuously using real-time acquired data by the downhole gauges. The second is an estimate of the zonal coverage based on the resulting temperature profile plot before, during and after a pumping treatment. Pressure transient analysis gives the skin as a direct output, while the cooling down/warming up DTS profiles identifies where the treatment fluids went in the formation, hence identifying the damaged zones. It is strongly recommended to combine well testing analysis techniques with zone coverage evaluation in highly deviated and horizontal completed wells in both clastic and non-clastic rocks. Basically, deriving the skin from the injectivity test (pretreatment) and the skin from the post flush (post-treatment) provides an evaluation matrix treatment effectiveness. A comparison between formation damage "skin" before and after the treatment was performed on the spot, revealing positive results of nearly uniform distribution of treatment fluids, and skin value reduction across the 3400 ft horizontal section. Following the innovative procedures executed in well-A, different techniques were proposed, providing time and cost savings; raising the operational excellence expectations levels higher than expected for an offshore environment. The application of FOECT technology helped to minimize uncertainties during treatmentevaluation, and enhanced treatment distribution and placement. In addition to establishing more accurate and reliable Nodal Analysis and production forecast models.
The Mauddud Formation in the Greater Burgan field is a thin carbonate reservoir with very low permeability but with moderate to good porosity and variable fracture density. The formation could be divided into three distinctive layers, based on the structural and digenetic complexities. Production in Mauddud wells show rapid decline due to tight rock matrix (low permeability). This decline is associated with an increase in Gas-Oil Ratio (GOR) as reservoir pressure falls below the bubble point pressure near the wellbore. Horizontal wells were drilled in an attempt to develop the Mauddud Formation targeting sweet zone. Most of the wells were located in a relative structural high on the up-thrown blocks of the North and Eastern flank of the Greater Burgan field that had the highest likelihood of intersecting fractures. They are mostly adjoining the major faults. There are now around 40 wells drilled in Mauddud including horizontal and multilaterals, most of which became non-producers due to above reasons. A study has been carried out to evaluate opportunities to revive these wells through available and new technologies in the industry. A detailed geological study incorporating all the available data was carried out initially. Wells were screened for stimulation by using various proven new technologies. Acid Frac, Stage Frac, near well bore SurgiFrac and Matrix Acid techniques have been applied with varying results. Advanced placement technique like distributed temperature profiling was used in some of the jobs. This paper presents the details of the application of the above mentioned technologies, to the candidate wells and discusses the results. The success of some of these technologies opened up new opportunities for a new beginning to revive the closed wells completed in Mauddud Formation.
Every year, the complexity of horizontal wells grows, and matrix stimulation of these wells is key for maintaining production levels and improving the draw-down from producing formations. In the subject field, many wells are drilled as mega-reach with measured total depths up to 33,000 ft. The mega-reach represents a significant challenge for coiled tubing to reach the total depth (TD) and perform well interventions such as stimulation and logging. Coiled tubing (CT) may lock up before TD, and it can be challenging to understand the root cause. One difficulty is differentiating between lockups due to the well conditions and bottom-hole assembly (BHA) malfunctions. Electric submersible pump (ESP) completions contain bypass assemblies that impose an additional challenge introducing a restriction in tubing internal diameters. The restriction is less than 2.50" in the completion, increasing to 8-1/2" for the open hole, extending for at least 5,000 ft laterally in the producing formation. With the large variation in internal diameter (ID), the hydraulic tractor option is excluded from the mega-reach aid list, though it has proven reliable in extending the reach of CT for 6-1/8" openhole sizes in the same field. Therefore, the challenge here is to derive the maximum output possible from fluidic oscillation vibratory tools to achieve forces close enough to tractor forces and ultimately accomplishing the intervention objective. A combination of mechanical and chemical solutions was the designated approach to tackle the challenge. After reviewing all the possible solutions, tractors were excluded due to the extreme expansion ratio needed resulting in lower pulling forces. A fluidic oscillation tool inducing axial vibration of an absolute magnitude exceeding 1,600 lbf was yard tested and deployed as a solution in combination with a selection of friction and drag reducers. This paper will illustrate the reach challenges, analysis performed, and show how we could utilize the latest developments in fluidic oscillation vibratory tools. It will also include downhole real-time data acquisition assisting the understanding of lockup occurrence, as well as quantifying the improvements in the pre-job tubing force model simulation.
Coiled tubing (CT) deployment with hydraulic tractors in extended reach open hole horizontal wellbores has been a challenging technology in the oil industry for reasons ranging from wellbore conditions like washouts to restrictions imposed by the completions. Consequently, delivering cost-effective well interventions solutions, for example through acid treatments to enhance well performance, or production logging to understand inflow profiles in deep injector wells have been particularly demanding. The authors examine how rigorous pre-job planning and teamwork were enablers to realizing the deepest CT reach at 30,365 ft (9.26 km) measured depth (+1,336 ft longer than the height of Mount Everest at 29,029 ft) in a mega-reach open hole horizontal power injector well using a CT tractor to facilitate effective stimulation in Saudi Arabia. Among the operational challenges overcome in the well was tar accumulation on the tool string including the tractor during the well intervention. The tar accumulation on the string was part of a laterally extensive high viscosity tar layer between the overlaying oil column and aquifer. From a reservoir standpoint the tar layer posed a challenge in assuring sufficient aquifer support to the oil producers because of their partial sealing nature. The author discusses how the challenges imposed by tar restrictions and other operational concerns were overcome to ensure successful acidizing. The wells showed a marked injectivity improvement from acid stimulation thus demonstrating the benefit of informed decisions from real time fiber optic distributed temperature sensing (DTS) in fluid placement. The tractor traversed a difficult down hole environment overcoming washouts and H2S environments within the wellbore conveying the CT for an industry record tractor reach for open hole CT intervention at 30,365 ft. Concrete applications of these outcomes include the ability to employ real time information for cost-effective stimulation and real time log acquisition from extended reach open hole horizontal wells.
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