One of the current largest oil increments in the world in Saudi Arabia is undergoing field development. The southern part of the field traverses the Arabian Gulf Sea. The Production Engineering team crossed major hurdles in the development of this field with Causeways construction on artificial islands over drill sites to assess well sites.Flowback options on wells in these drill sites to unload drilling fluids presented key challenges. The flowback objectives included well cleanup, stimulation, production logging, and extended well tests for reservoir characterization requirements. Flowback would also allow conducting electric submersible pumps (ESP) spin tests prior to ESPs installation.A smokeless flaring option considered the heavy crude's characteristics with relatively high H 2 S content, possible emulsions from intermixing with completion fluids, interwell spacing limitations, and the sensitive nature of the nearby challenging marine environment. The choices were between using a conventional flare system and modifying the proposed layout to optimize the project's objectives while respecting the constraints imposed by a sensitive aquatic environment, highly sour crude, space limitations, and work conditions or implementing pre-existing conventional practices with the attendant risks of compromising health, safety, and environment.The authors examine the processes leading to the implementation of a smokeless and an environmentally friendly flowback option. The discussion includes the modifications made to the burner system, and H 2 S removal from the gas and oil phases. Also a new methodology is presented that fully controlled oil and gas flow to the burner to mitigate the risk of burner flameout for the highest burning efficiency, minimizing spills, and enhancing safe operation. The authors examine the pros and cons of other welltest options such as to re-inject produced fluids into the same reservoir, different reservoirs, or injection into water injectors.Key significant technical contributions include the presentation of several practical measures to avoid oil spills, and to guarantee ambient air quality. The welltest layout included several automation systems or the elimination of human interventionto deliver safely the project's objectives. BackgroundThe drill sites sit on artificial islands constructed from piles of gravel and sand in about 22 feet of water. The Causeway concept itself was borne out of a need to protect the beds of sea-grass and algae in X bay, which supply abundant food for aquatic existence. The beds of sea-grass and algae are therefore the perfect home for species like shrimp, dolphins, crabs, fish, sea turtles, oysters, and some endangered classes. A prime objective was to sustainably manage the X field development while preserving this inherited fragile but untainted legacy of the environment. In addition to the sensitive marine habitat, proximity to public areas, limited well spacing, and a relatively high H 2 S amount in the crude all contribute to the challenging nature of thi...
Well intervention in horizontal extended reach wells (ERWs) comes with a myriad of challenges and in the case of coiled tubing the overarching impediment is in reaching the target depth (TD). Frictional forces act against the coiled tubing (CT) while being pushed from surface, this eventually leads to helical buckling of the tubing and early lockup where no further progress is made. Advances have been made over the last decade with the development of high-tech downhole CT tractors that deliver a strong pulling force to overcome these frictional forces. Restrictions in the well completion require these tractors to collapse to 2-1/8″, and then to expand to the cased or open hole size of up to 6-1/8″. With many wells having a larger bore size of 8-1/2″, a CT tractor did not exist to improve the coverage in those type of wells. At first glance, modifying the existing tractor for 6-1/8″ sized holes to function in 8-1/2″ sized holes could be accomplished by simply extending the lengths of the arms. However, the reality is a little more nuanced with several innovations required to deliver the same pulling force as the 6-1/8″ tractor version. This new generation of downhole compact high expansion tractors have improved push-links and newly designed grippers to enable rig-less acid stimulation and production logging in ERWs. The high expansion tractor is an important facilitator in CT well interventions to tackle challenging ERWs by increasing the coverage in 8-1/2″ hole sizes. The CT tractor design, development, testing and first deployment was conducted in 2021. The major advantages gained from increasing the reach can be summarized as follows: The CT high expansion tractor enables successful reservoir surveillance and production monitoring, including improved reservoir understanding providing data to update and calibrate reservoir models.Acid stimulation in 8-1/2″ open hole wells on CT targeted fluid placement to improve well productivity to increase revenue per well.Detecting and then shutting off water inflow zones with CT techniques, avoiding the need for drilling a side track. This new generation of slim tractors is the first in the industry to operate in wells with a diameter of 8-1/2″ and an operating range from 8″ to 10″. The key metric to successful acid stimulation or logging applications in ERWs is the ability to achieve maximum coverage of the openhole section. These engineered solutions demonstrate how creative innovations in technology design are improving accessibility in ERWs, resulting in superior reservoir management outcomes.
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.
This case study focuses on a Middle East giant carbonate oil field drilled with horizontal producers and water injection wells. In this particular field, formation pressure while drilling measurements are primarily used to characterize the mobility of the formation fluid, to ensure injectors are optimally placed in good injectivity intervals and producers in high productive zones. Acid stimulation is required to mitigate drilling induced reservoir damage. Owing to the length of the open hole sections and the high heterogeneity of the formation mobility, effective placement of acid is very challenging. Viscoelastic diverting acid is commonly used to assure good zonal coverage across each stimulation stage, but the length of the extended reach wells requires optimum diverter placement for cost effectiveness. An innovative methodology using distributed temperature surveys (DTS) with fiber optic enabled coiled tubing was introduced to compare pre-treatment injectivity with the mobility profile acquired while drilling before formation damage has occurred. The predicted injectivity/productivity profile computed from mobility measurements is used to establish the fluid placement strategy during the pre-job planning stage to decide on the required amount of acid and diverter. During the matrix stimulation operation, the temperature profiles after an injectivity test are compared with the baseline DTS temperature and mobility profile to identify thief zones and intervals with drilling damage. The availability of this information at the well site during the acid treatment allows the selective placement of diverter fluid across the thief zones, verification of the effectiveness of the diversion, its distribution along the wellbore, and accurate spotting of acid across damaged zones. By implementing this process, under stimulated intervals close to the heel section, which has longer exposure time to the drilling fluids, were identified. The current practice of pumping alternating stages of acid and diverter for certain lengths of wellbore segment has been revised and a new optimized approach was introduced. The new methodology has been applied to several wells and has allowed a better use of available treatment fluids to obtain more even injectivity/productivity profiles and maximize stimulation effectiveness.
Intervention work is often necessary in field developments with deep wells to enhance well performance through acid stimulation. Acquisition of flow profile data in these wells is also vital for decision making. Deploying rigless solutions for monitoring of well enhancements and injection zones in the extended reach wells presents both technical and economic challenges given the tortuous nature of these wells, dogleg severity, considerable variations in azimuth and hole inclination, washouts and general hole conditions. Significant intervention cost savings have been observed since hydraulic tractor-aided coiled tubing (CT) intervention was introduced in ultra deep wells in the development of a Saudi Arabian field three years ago. Specific stimulation benefits include reduction to skin damage, improved drawdown, and treatment gains from injectivity increase. While tractor aided coiled tubing has largely been demonstrated as a preferred deployment technique for cost-effective acid stimulation and memory production logging in extended reach wells, the subjects of real-time evaluation of treatment effectiveness and injection zone monitoring have remained an industry challenge. The limitations of memory production logging have been compounded by spinner failure from organic residue dropouts in the wellbore while logging (which cannot be identified with the memory production logging tools until the end of the job). Apart from the lost time and loss of data, operational cost is extended beyond the allocated budget from re-runs, thereby adversely affecting development schedules. From this experience evolved a design to run real-time production logs in such challenging wells with potential for triggering data problems and delivering better quality wells. With improvements in job design, the first real-time production logging job trial was successfully performed in a 9.1 km well with a measured depth to the true vertical depth (MD/TVD) ratio greater than 3.44 in Saudi Arabia. This case study reveals how real-time information was employed to effectively stimulate and perform real-time production logs of an ultra deep well in Saudi Arabia. Practically, the work shows that effective stimulation and real-time production logging are possible in ultra deep wells. Introduction Through extended and mega reach technologies, the oil industry has been able to access reservoirs unattainable to conventional completion and drilling techniques. Blikra, Drevdal, and Aarrestad (1994) defined extended and mega-reach wells on the basis of measured depth to the true vertical depth (MD/TVD) ratio of the wells. According to the definitions offered by Blikra, Drevdal, and Aarrestad, wells with MD/TVD greater than 2.0 are extended reach wells, while the wells with MD/TVD ratio greater than 3.0 are mega-reach wells. For simplicity, extended and mega-reach wells are referred to simply as ultra deep wells in this discussion. The purpose of the tractored CT enabled real-time production logging run was to enhance the gains of coiled tubing (CT) placement and the apparent mechanical diversion of stimulation fluid treatment across the entire + 6,697 ft open hole in an injector well. The reason for well stimulation was to reduce skin damage from mud filtrate and particle invasion from drilling and well completion fluids into the reservoir as well as to establish uniform contribution from the entire openhole horizontal section. Stimulating the injector wells will enhance their injectivities for a favorable waterflood during the injection scheme.
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