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Abstract Since the concept of milling obstructions on electric line (e-line) was introduced in 2005, operators around the world have applied this technique successfully removing downhole valves, plugs, scales, cement and nipple profiles achieving cost-effective and time-efficient interventions. Recently, a series of e-line milling operations were performed to remove repeater-sub and ball-seat restrictions in oil producing horizontal wellbores located in Southeast Saskatchewan. The low pressure reservoirs favored intervention technologies that did not require excessive hydrostatic head. Operators have traditionally used nitrogen mixed with water to prevent damage to the reservoir and to maintain circulation; however, this reduces the amount of torque that can be achieved at the bit, and causes stalling and sticking issues. Using a combination of tractor and milling technology on e-line in these wells provided the required torque for milling with a steady and constant weight on bit throughout the wellbore for removal of ball seat restrictions. This paper presents the latest achievements within e-line milling in Canada. The paper will discuss best practices of date as well as a discussion of e-line milling challenges through three case studies in Canada.
- North America > Canada > Saskatchewan > Williston Basin > Bakken Shale Formation (0.99)
- North America > Canada > Manitoba > Williston Basin > Bakken Shale Formation (0.99)
Abstract The excess of water production from oil wells in several areas of Khafji field is a subject of concern for reservoir management. Water shut-off techniques are common practices to reduce water production which is resulted in well productivity improvement. An oil producer well-A, was worked-over on February 22, 2006 to conduct a water shutoff technique on existing perforation intervals utilizing a cement squeeze. Several logs such as RST and Gamma Ray were carried out to identify the fluid movement. Then, the well was produced with an oil rate of 1,200 BOPD and a rapid increase of water cut of 60%. The well was still unstable in terms of rate due to high water cut. The well was considered for rigless work-over to control the water using Mechanical Through Tubing Bridge Plugs (MTTBP) to isolate the lower two perforation sections. After setting the Bridge Plug with 8 ft. of cement above the plug, the well was revived with production stream. During the first 24 hrs of well production, the treatment result was not as expected which resulted in 100% water cut. A discussion was made by reservoir management engineer to continue of production for additional 24 hrs. With time, the well showed a positive result with a reduction in water up to 95%. It is recommended to keep the well to be produced over 21 days with final results showed the well revived with an oil production of 1,500 BOPD with zero water cut. The result showed a successful water shutoff technique and scenario to retrieve the well with 100% water cut produced after treatment. Challenges, intervals selection, design criteria, lessons learned, and results of the water shutoff technique will be discussed in this paper.
- Geology > Mineral (0.47)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.31)
- Asia > Middle East > Saudi Arabia > Saudi Arabia - Kuwait Neutral Zone ("Partitioned Zone") > Arabian Gulf > Arabian Basin > Arabian Gulf Basin > Khafji Field (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Lower Fadhili Formation (0.99)
- Asia > Middle East > Saudi Arabia > Eastern Province > Al-Ahsa Governorate > Arabian Basin > Widyan Basin > Ghawar Field > Khuff D Formation (0.99)
- (6 more...)
Innovative Solution Successfully Recompletes Problematic Well in Malaysia
Elliott, Chris (Petronas Carigali Sdn, Bhd (PCSB)) | Mahzan, Mohammad (Petronas Carigali Sdn, Bhd (PCSB)) | Feroze, Mohd Imran (Petronas Carigali Sdn, Bhd (PCSB)) | Mahadi, Khairul Azmi (Petronas Carigali Sdn, Bhd (PCSB)) | Mahdzan, Abdil Adzeem (Petronas Carigali Sdn, Bhd (PCSB)) | Aziz, Khairil Faiz (Halliburton) | Forbes, Murray (Halliburton) | Dzul-Fikar, Nasri (Welltec)
Abstract An offshore operator in Malaysia had run a completion string in a highly deviated 7-in. gas well. When continuous pressure build-up in the production casing annulus was observed during well clean-up, leakage in the completion system was suspected. After several attempts to mitigate the pressure build-up failed, the operator initiated further investigation, which confirmed the suspicion. Small tubing leaks that were allowing produced gas inside the tubing to seep through to the annulus were found. These leaks could have allowed the pressure to increase, and possibly, could have caused the casing to collapse. In order to produce through the annulus, the pressure would have to be vented. With the high demand of gas in Malaysia and since the rig was still at the location, the project team decided to initiate immediate recompletion of the project instead of waiting for a later intervention. This well is one of three wells completed to develop the FN field within KCL area, located approximately 200 km offshore from Bintulu. The field was expected to deliver up to 100mmscf/day per well to help relieve an anticipated gas shortage. This paper discusses the history of the wells, the diagnostic methods used to analyze the well problems, the pros and cons of each solution considered, details regarding the recompletion chosen, and the challenges encountered during the recompletion activities. The discussion also highlights the successful solution used for closing and reopening the fluid loss isolation barrier valve (FLIBV) with a wireline tractor rather than with other options considered after conducting a successful system integration test (SIT) prior to the project execution. The unique solution chosen was a first for Malaysia, and probably, for the world. The success of the recompletion results provided improvements for future applications and will be a benchmark solution for future operations.
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Operations (1.00)
- Well Completion > Well Integrity (1.00)
- (8 more...)
Abstract In the quest to increase reservoir contact, horizontal drilling and multi-stage hydraulic fracturing is the common theme in the stimulation of productive shale reservoirs. Twenty to thirty stage fracs are not uncommon in some of these reservoirs. Cost, and sometimes safety considerations, can lead operators to make do with minimal information in the laterals. The selection of frac intervals is often guided by measurements in the pilot hole and stages are placed more or less evenly along the lateral. Field examples presented here highlight the fact that comprehensive LWD or openhole wireline data, acquired with the special deployment techniques in the lateral, clearly demarcate the good zones (sweet spots) from intervals with inferior reservoir characteristics. LWD Spectral GR has proved its worth in this regard and an innovative acoustic LWD measurement has provided valuable data in the laterals that has aided stimulation design. An original approach involving real time monitoring of hydrocarbon (C1 – C8, benzene, toluene) and non-hydrocarbon gases (CO2, N2) dissolved in the drilling fluid in the mud stream has proven successful in independently identifying sweet spots in the laterals. On the other hand, near real time measurements of XRF, XRD and pyrolisis measurements on drill cuttings at the wellsite have clearly established their worth in identifying zones suitable for stimulation. Field examples presented here demonstrate how these techniques have been successfully used to identify sweet spots and have thus helped enhance the effectiveness of hydraulic fracturing, resulting in improved production from shale reservoirs. Production data are presented to show how productivity is enhanced by concentrating on sweet spots.
- North America > United States > Texas (0.94)
- North America > Canada (0.69)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.69)
- North America > United States > Texas > Haynesville Shale Formation (0.99)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Louisiana > Haynesville Shale Formation (0.99)
- (8 more...)
Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Russian Oil & Gas Exploration & Production Technical Conference and Exhibition held in Moscow, Russia, 16-18 October 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited.
Abstract This paper describes a new water shut-off approach for wells challenged by coning (changed shape of the cone of depression) by injecting the DSGA (Drilling Specialties Gelling Agent) polymer solution with an additional consolidation by cement slurry with improved properties. This approach was implemented at Samotlorskoe Field of TNK-BP Company. This project was implemented as part of pilot works on monolithic and compartmentalized terrigenous formations AV4-5 and BV8(1–3). The technology deployment scope includes the formations with the system of induced fractures and water breakthroughs, high-permeable interlayers, bottom water, impact of displacement front of injectors. Injection of gel into formation results in a reduced volume of produced water, reduced fluid rate and increased formation drawdown in producers. Injection of gel into formation provides for an increase of pressure gradient between injection and recovery zones and change in direction of in-situ filtration flows. Oil-saturated interlayers of low permeability and watercut previously not covered by displacement are involved in the active reserve recovery process. This results in a reduced volume of produced water, reduced fluid rate and increased formation drawdown in producers. Increase of well stream watercut is observed in mature fields. This requires deployment of technologies to limit the water inflow. At present, the sources of water inflow are controlled by various technologies — from conventional cementing to use of various mechanical packers and advanced chemicals. Efficiency of deployed water shut-off technologies can be improved by developing and perfecting the procedures for selection of candidate wells for remedial cementing and also using the holistic execution of works. Increased of watercut level is caused by several factors such as rise of oil-water contact, inflow of injected and edge water, casing leaks, bottom water coning and crossflows. The watercut of well stream can be increased due to poor quality of well cementing. In this case a mud cake is formed on borehole walls interfering good adhesion of cement and rock. This mud case is washed away during the well operation that leads to fluid migration between formations. Use of cement slurries with very low fluid loss can lead to an insufficient dehydration of slurry and consequent low quality isolation of perforations or damage of casing string. Very fast dehydration of the slurry with very high fluid loss can lead to unstable cement not able to withstand pressure drop. Poor quality of cementing results in formation of water and gas fingers during the setting time, improper adhesion of cement and casing string during the cyclic loading, uncontrolled loss of circulation. Fractures are developed in the formation during cement squeezing due to the overpressure. Lack of cement leads to fluid flow, which is aggressive to metal and becomes a reason of through corrosion holes in the casing string. Water entry causes circulation in the casing cement in the points of contact of casing joints with cement and cement with bore wall. Moreover, water ingress may occur due to lost integrity of cement caused by damaged cement plugs and casing leaks. Typically, integrity of set cement is lost as a result of mechanical damage during tripping, expansion of casing string and compression of cement from pressure tests, expansion and compression of pipes due to cyclic changes of pressure and temperature during well operation. Moreover, integrity of set cement can be damaged by perforation that creates impact loads on casing string.
- Europe > Russia (0.28)
- Asia > Russia > Ural Federal District > Khanty-Mansi Autonomous Okrug (0.25)
Annotation The Vankor Field is being developed as network of horizontal production wells, with lateral filter length of not less than 1,000 m. The completion systems options include Equalizer™(Schlumberge), ResFlow (Baker Hughes) systems as well as various designs of slotted and screen filters made by Russian manufacturers. With the purpose of achieving planned oil production capacities and oil recovery factors, it is critically important to save formation reservoir properties and prevent clogging of bottomhole formation zone. For this purpose we analyzed the market of technologies used to eliminate contact of killing fluid with bottomhole formation zone during intervention and workover operations, and selected bottomhole shut-off valves for the Vankor Field conditions. The main challenge of shut-off valves design selection is the functional possibility of conducting geophysical surveys using coiled tubing in lateral hole below packer set interval without prior retrieval of the packer. By the time of selection, the Halliburton serial shut-off valves completely complied with these conditions but the implementation process was complicated by problems related to setting of shut-off valve in the G-6 packer seat due to complex wellbore profiles and deviation angles up to 90 degrees. This publication describes the result achieved by joint operations of ZAO Vankorneft Oil and Gas Production Department specialists and Halliburton design engineers, which enabled us to successfully apply shut-off valves in the Vankor field wells.
- Asia > Russia > Siberian Federal District > Krasnoyarsk Krai (0.93)
- North America (0.89)
- Asia > Russia > Siberian Federal District > Krasnoyarsk Krai > Vankorskaya Area > Vankorskoye Field (0.99)
- North America > Canada > Alberta > Adams Field > Canlin Adams 7-3-71-8 Well (0.98)
- Asia > Russia > Siberian Federal District > Krasnoyarsk Krai > Vostok Oil Project > Vancor Cluster > Suzunskoye Field (0.94)
Abstract Kharyaga field is a complex karstified carbonate reservoir located in a harsh arctic environment of Timan Pechora region on the North of Russia. The main Kharyaga reservoir, still under development, is subdivided on several layers and is characterized by an important heterogeneity (spacial distribution, fractures, karstified areas, etc …) leading to a very complex flow distribution in the reservoir (sweep efficiency) as well as in the well (water breakthrough, possibility of cross flow). In addition, the oil of this reservoir is waxy crude with high positive appearance pour point temperature. High dynamic data quality and adequate real time follow up is mandatory for proper reservoir behavior understanding and characterization in order to be able to take effective operational decisions in due time and then maximize production level. Estimation of each layer contribution to the overall production allows proactive reservoir management including real time follow up and well intervention planning. Fiber optic systems were installed as a part of the upper completion system below ESP in front of perforated interval. Each development pad is equipped with permanent DTS (Distributed Temperature System) to acquire temperature traces data in selected wells. An innovative system was implemented in order to ensure temperature traces acquisition, transfer and storage in real time to Moscow office, which allows reservoir engineer to interpret in real time and upon operational request any variation (well rate, watercut increase, Wax deposition evolution along the well, etc…) and take well-informed decision. This new procedure allowed to reduce drastically the time needed to integrate temperature information thanks to human interference reduction in the data transfer and data storage. Real time qualitative interpretation, thanks to real time data, allowed curative program and improving scrapping frequency leading to production gain. In this paper, interpretation and action plan taken will be described in various conditions, such as: –Determining the contribution of main contributing layer in a single phase flow well - 90% of inflow was produced only from first 20 m out of 45 m perforated height –Identified a primary water-flooded zone after rapid water breakthrough. This zone was isolated leading to a 50% watercut decrease –Detecting water cross flow from a shallower water bearing reservoir into Kharyaga reservoir. A cross flow rate was estimated based on acquired temperature data and help designing remedial work-over. Cross-flow was successfully eliminated and the well was put on stream as producer with pure oil thanks to adequate remedial work over design Obtained knowledge brings better understanding of the field behavior and revision of the object development strategy.
- Europe > Russia > Northwestern Federal District > Nenets Autonomous Okrug (0.63)
- Europe > Russia > Central Federal District > Moscow Oblast > Moscow (0.26)
Abstract Deepwater wells using fracpack stimulation are progressively moving to ultradeep water depths and total depths; the bottomhole pressures (BHPs) and temperatures of future reservoirs could exceed 20,000 psi and 250°F. To safely perform deepwater fracpack treatments, the following pressure and tubular limitations should be considered: Maximum surface tubing pressure because of pipe limitations and gravel pack assembly component ratings. Maximum surface annulus pressure because of blowout preventer (BOP) ratings. Maximum allowable tubing movement while pumping to help prevent premature job cessation. Maximum allowable downhole slackoff and overpull because of well path, pipe, pipe connections, and downhole component ratings. Depending on the well depth, pressure, temperatures, and BOP type (subsea or dry-tree), various pipe, connection, or equipment limitations might be exceeded during multistage fracpack stimulation operations. Initial pipe loading as well as pre-fracpack stages, such as the pickle, acid treatment, or minifrac calibration treatment, will alter the pipe failure and movement conditions and must be accounted for in the final completion design. Because of these concerns, a workflow process has been delineated to evaluate the maximum allowable treating pressures, tubing movement, and tubular limits for deepwater subsea and dry-tree fracpacks across four components: Input component to consolidate well and stimulation data for further workflow analysis. Surface treating pressure evaluation component to analyze certain treating pressure limitations. Commercial wellbore, casing, and tubing simulator to evaluate work string safety factors, tubing movement, and downhole forces. Commercial torque and drag simulator to evaluate surface slackoff requirements and allowable work string overpull. A description of the variables, range of values, and other considerations for each of these four components is discussed, and the benefits of using this process to evaluate fracpack stimulation are shown. Well case histories are also used to support this process.
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drillstring Design (1.00)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- (12 more...)
Abstract The deepwater Gulf of Mexico is a technically and economically challenging production environment. High rate and ultimate recoveries per well are required to offset high development costs. Stimulation is employed to maintain wells at peak production rates and accelerate reserve recovery. In the complex layered reservoirs of the deepwater Gulf of Mexico stimulation is also necessary to ensure volume recovery. The primary objective of stimulation is to restore impaired well /reservoir connectivity. In complex reservoirs this may be reflected in either a reduction of skin or improvement in apparent permeability height. In poorly consolidated sandstone reservoirs production may become impaired during completion operations by suspended solids, polymer residue, or incompatible fluid systems. During production fines migration, scale deposition, and organic deposits in the near wellbore and sand control system can lead to declining inflow performance. Successful identification of the cause and location of impairment is required for success. The increasing population of subsea wells creates new challenges for intervention. Correct operation of the well post stimulation is also necessary to achieve the desired rate increases without compromising production system performance. The nature of impairment, treatment options, and post treatment production issues often change over the life of the well. Looking back over a decade of experience in this challenging environment yields useful insights as we move into new deepwater provinces.
- Geology > Mineral (0.71)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.68)
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment > Deep Water Marine Environment (0.47)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.31)
- North America > United States > Texas > East Texas Salt Basin > Shell Field (0.98)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Auger Basin > Garden Banks > Block 426 > Auger Field (0.89)
- North America > United States > Gulf of Mexico > Central GOM > East Gulf Coast Tertiary Basin > Viosca Knoll > Block 957 > Ram Powell Field (0.89)
- (17 more...)