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Abstract In this review paper, a variety of reservoir applications are indicatedwhere horizontal wells (HWs) can have advantages over the use of conventionalvertical wells. Analytical methods for calculating critical coning rates inhomogeneous reservoirs are reviewed, and shown to give a very large range ofresults for HWs. Some aspects of assigning effective parameters to flexiblegridding schemes for HWs are presented. The potential significance of two-phasepressure drop within the wellbore on GOR performance is discussed, and a rangeof uncertainty by a factor of six is indicated between the use of variouscorrelations for calculating the well pressure drop. In the final sectionstudies are summarized for a gas coning application using Eclipse, a commercialsimulator. Conditions under which the wellbore pressure drop becomes importantare demonstrated. Introduction Horizontal wells (HWs) have provided a major breakthrough in new techniquesfor developing oil fields; the drilling technology was first pioneered by Elfaquitaine and the Institut Francais du Petrole (IFP) with application in theoffshore Raspo Mare field in the Adriatic (circa 1977). Since then thetechnology has expanded enormously with one assessment indicating over 800horizontal wells being drilled in 1991. Some 2,500 HWs are known to have beendrilled to the end of 1992 in the USA. Drilling costs have decreased to be onlyabout 1.3 times those for vertical wells, even with horizontal sections of2,000 feet or more. Although the drilling techniques in association with Measurement While Drilling (MWD) have progressed to remarkable accuracy, and inmore recent years clearer insights have been established on completionpractices, the reliable prediction of the reservoir engineering and performanceattributes of horizontal wells remains a severe challenge. For example, in the Prudhoe Bay field where reduction of gas coning under an expanding gas capprovides an incentive, Sherrard et al., the use of horizontalwells has sometimes not been as beneficial as first anticipated. Part of thishas been attributed to a rapid build-up in gas/oil ratio after gas breakthroughinto the well. In vertical wells, however, techniques for an optimalrecompletion of the well to offset gas coning behavior can be used withreasonable confidence, thus the economic benefits for horizontal wells are notalways clearly assured. This raises the important question of optimalrecompletion strategies for long HWs.
ABSTRACT A new approach to complete horizontal wells is proposed to make futurestimulation work much more effective. Current well design formulations, largelyinfluenced by vertical well technologies, do not tend themselves well tofurther stimulation. Treatment of wells that have been depleted tononeconomical levels may generate marginal production increases. The new method uses hydrajetting technology to enhance the ability tosuccessfully stimulate a horizontal well. It uses a hydrajetting tool that iscapable of creating fan-shaped slots in the formation behind the casing inorder to direct fracture initiation correctly. Only limited size slots are cutthrough the casing, thus maintaining its integrity. Using this new approachwill result in more effective treatment of localized areas, and willdrastically improve stimulation or damage-bypass treatments. Tortuosities offracture paths are reduced if not eliminated. Patent applications have beenfiled on the subject matter contained in this paper. INTRODUCTION Horizontal wells have a large potential to improve the oil production ratesand ultimate recovery of many reservoirs. This improves the attraction of theindustry to this technology, especially with the advanced stages of drillingand completion technology in this area. In fact, it has been demonstrated thatre-entering an existing vertical wellbore to drill a horizontal segment iseconomically feasible. When low cost is the overriding concern in completing a horizontal well, openhole completions are generally selected if borehole stability is not aproblem. Such completions, however, do not provide options for remedial actionsin the future. In addition, this type of completion does not allow effectivemeans for abandoning the well, and may be costly to manage during the laterstages of the life of the well. Slotted liner completions provide advantages over the openhole method bytheir relatively low cost, yet better protection against wellbore collapse.However, as in openhole completions, slotted liners provide very few optionsfor remedial procedures. Cemented casing completions are the most expensive, but they provided, mostoptions currently available in vertical well technology. Effectivestimulations, isolation of zones, and other remedial actions are possible. Wellabandonment can also be performed effectively.
This reference is for an abstract only. A full paper was not submitted for this conference. Abstract Excessive water production is often associated with mature fields. The source could be from the aquifer providing reservoir energy or waterflood process used for sweep enhancement. The adverse effect on oil production and reserves requires that a remedial action should be implemented to minimise the overall impact. An effective remedial action requires the identification the source of the problem. This paper discussed the use of intelligent well technology to control the amount of water production from a multi-lateral well in a mature asset in order to maximize overall oil production. The multilateral wells were drilled to connect the identified sweet spots and boost oil recovery. The field water cutranges from 20% to 100% with an average of about 75%. The main challenge facing the asset is improving waterflood efficiency and reducing percent water cut of produced fluids. As a solution, the operator installed a Digital HydraulicTM Smart Well system that allows for isolation of each lateral branch in the producers. This system enables an independent control of the contribution of each lateral for production optimisation. This same isolation technology can be applied to water injection wells to improve the waterflooding efficiency. The system consists of remotely operated binary position control valves and downhole packers that isolate water producing areas of the well. An ESP installation is integrated with the provision of a hydraulic disconnect, allowing the replacement of the ESP without affecting the lower completion. The disconnect tool provides re-establishment of hydraulic control line continuity upon ESP replacement. Production tests carried out after two months of installation indicate a significant reduction in water-cut from 99% to 71% resulting in over 400%increase in oil production. Additional oil ultimate recovery is estimated to be about 5.6 million cubic metres. This case study demonstrates the ability of the intelligent well system to identify and control the production of unwanted water without intervention, accelerate production, increase ultimate recovery and lower operating cost.
Gas Seepage at the Sea Floor, Part 2: The Remedy and Results
Al-Marri, F. (Abu Dhabi Marine Operating Company) | Fawakhiri, A.Y. (Abu Dhabi Marine Operating Company) | Rouatbi, R. (Abu Dhabi Marine Operating Company) | El-Zeghaty, Said (Abu Dhabi Marine Operating Company) | Dajani, N. (Abu Dhabi Marine Operating Company) | Boyd, D. (Abu Dhabi Marine Operating Company) | Cossey, Simon (Abu Dhabi Marine Operating Company) | Okuyiga, Moyo (Abu Dhabi Marine Operating Company)
Abstract This paper documents the job methodology and the remedial cementing actions taken to cure an offshore subsurface gas and oil leak in a prolific gas producer that crosses multiple, hydrocarbon-bearing horizons. It is a follow-up to ADIPEC- 0938 describing the investigative process used to diagnose the multiple leak sources. A detailed risk assessment and contingency plan preceded each operation. Seven squeezes proved necessary to control the leaks. Continuation of the leak to surface and downhole noise activity defined the success or failure of each cementing operation. Cement squeeze operations took place through two to three sets of casing, after perforating with TCP guns at shot densities from 12 to 36 shots per foot. An ultrafine cement formula ensured the smallest diameter flow conduits were penetrated. Monitoring of the annuli leak rates over a sixteen-month period with a custom designed separator, suggests the leak is cured. Final declaration of success or failure must wait until the well is place back on line following its recompletion. Introduction During the shallow drilling phase of the fourth well on a platform situated in the Arabian Gulf a small explosion occurred. The fuel was a gas accumulation caught between the 30" conductor and 20" casing. Ignition occurred during hot cutting of the newly cemented 20" casing. The presence of gas was puzzling, as the well had not yet penetrated any known hydrocarbon-bearing formation. Divers sent to investigate the platform structure condition, discovered gas bubbles percolating up from a number of cracks in the cement grout covering the sea floor. Two of the wells on the platform are auto-injectors, separately pressurizing Cretaceous and Jurassic oil reservoirs. They receive gas from a deep Permian producer on the same platform. The incident well was intended as an additional gas supplier. Investigation of the platform wells with cased hole logs, annulus pressure monitoring and well history review, pointed to the Permian gas producer as the problem well. It contained pathways via cement channels and empty space between 9 5/8" × 13 3/8" and 13 3/8" × 20" casing strings for gas and oil to leak to surface from the Cretaceous and Jurassic reservoirs under gas injection. A casing diagram and the diagnosised hydrocarbon flow paths of the culprit well is presented in Figure 1. Job Planning A detailed Job Plan and Decision Trees were formulated before the job by a multi-disciplined team of reservoir, petroleum, drilling, engineering and safety engineers. Several months were invested in laying out the operations details and job strategy. The team reported and discussed its progress regularly to a Steering Committee composed of senior management. The mandate of the team was to repair the leak while ensuring the safety of personnel involved and the tower.
- North America > United States (0.28)
- Asia > Middle East > UAE (0.15)
- Phanerozoic > Mesozoic > Jurassic (0.54)
- Phanerozoic > Mesozoic > Cretaceous (0.47)
- Phanerozoic > Paleozoic > Permian (0.34)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.98)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.98)
Abstract Objectives/Scope Objective of this paper is to describe a methodology applied to overcome production logging challenges in a horizontal/deviated, low pressure and high water cut well in order to determine flow profile and zonal phase contribution. Method, Procedures, Process Conventional production logging with Electric wireline in the deviated/horizontal and low pressure wells is becoming a challenge. Measuring an inflow profile and identifying water producing intervals in low pressure high water cut wells require an improved methodology. Electric wireline conductor cable placed inside coiled tubing (CT) creates new opportunities for logging and induces well production while logging. Subsurface information obtained from recently drilled Jurassic wells indicates presence of hydrocarbon accumulation beyond present limit. A new well has been drilled and completed with 7″ liner to prove the hydrocarbon in a new reservoir. The well was perforated in underbalanced condition and tested with Drill Stem Test (DST). There are four perforation intervals in the deviated profile. The promising four layered carbonate formations produced 100% water while lifting the well with Nitrogen. Acquisition of flow profile data in this well is vital for decision making. It was required to diagnose the contributing and non-contributing intervals to decide on the suitable remedial action. Low pressure with high water cut reservoir becomes a challenge in measuring inflow profile and identifying water producing intervals. Electric Coiled Tubing (E-CT) was used to convey the production logging tool while pumping Nitrogen to lift the well production to acquire inflow profile data. Surface well testing equipment was used to measure the surface flow rates. Shut-in survey and flowing survey were performed to identify presence of water behind casing, cross flow and water entry. Multi-finger Imaging Tool (PMIT) was used to measure the internal diameter of the casing strings to confirm the presence of the perforation intervals. Results, Observations, Conclusions Well production was induced by pumping N2 through E-CT while production logging. Inflow profile data was successfully acquired from a deviated, low pressure and high water cut well using production logging tool (PLT) attached with coil tubing. Production logging results showed that all of the water production is coming from the top part of the third perforation intervals. During Shut-in Survey, it was observed that no cross flow between the perforation intervals and no observation of flow behind casing above or below the perforation intervals. Furthermore, it was observed that the PMIT logs clearly proved the presence of all 4 perforation intervals. The data acquired using E-CT production logging confirmed the contributing and non-contributing intervals which provided a clear vision to take a remedial action. Novel/Additive Information For the first time in Kuwait, E-CT was successfully used to record flow profile in horizontal/deviated exploratory well while Nitrogen lifting. This successful application will help to acquire production logging in the wells with similar condition.