When wells have come to the end of their lives, it becomes necessary to plug and abandon them and return the seabed to its original condition. In the UK sector of the Central North Sea (CNS), an operator managed 6 fields comprising a total of 30 subsea wells in 7 clusters, required to be plugged and abandoned. These fields are among many that are coming to the decommission stage, with the over-riding requirement from the UK government being that of no leakage of hydrocarbons to the environment or between separate permeable geological zones. The operator standards required the placement of two cement barriers of a minimum of 100-ft each for zonal isolation. The preferred route was to find the annular portion of the barrier by interpretation of ultrasonic imaging tool in combination with the cement bond (CBL) wireline logs used for cement evaluation service, then to set a 500-ft plug inside the casing opposite that zone. In the case that no barrier quality cement was identified in the annulus, section milling of the casing was undertaken to expose 100-ft of formation over which cement was placed. A number of challenges were faced to design the cement slurry prior to the logging results. The setting depth may only have been confirmed a few hours before the cement job. To cover the possible setting depths and temperature ranges, laboratory testing consisted of performing temperature sensitivity tests on base slurries designed with a wide temperature range retarder, but still optimizing the system to minimize wait on cement (WOC) time. A specialized high magnesium resistance (HMR) cement system that provides long-term zonal isolation and protects against cement degradation was identified as being best solution. The HMR cement is a blend of blast furnace cement and fly-ash, which reduces the cement permeability and limits the effect of alkaline brine corrosion. Optimal plug placement was also required for long-term isolation. Specialized plug placement software that accounts for in-pipe and annular contamination, and fluid interface matching during pulling out of the plug was utilised. The slurry design and emplacement best practices will be summarized in this paper. These subsea wells have been successfully plugged and abandoned by laying temporary, primary, secondary and environmental cement barriers by several different methods: inside casing, across section-milled windows, multi-annular, through scaled production tubing and through coiled tubing according to each particular well's condition. Success ratio was exceptionally high with all the long term barrier themselves being flawlessly placed and verified without any repeat job being required.

The company and a vendor teamed up to optimize the gas-lift injection process in offshore dual string oil wells in BM, Malaysia. This paper outlines how the real-time production data and well model approach help to overcome the challenges faced in dual string gas-lift wells and to improve their performance. There are many challenges to manage a brownfield specially to get high quality data. Challenges include -• Integration of various data sources, improving data quality and automation of engineering workflows.• Calculation of well Inflow Performance Relationship (IPR) as composite IPR for commingled flow when reservoir information is limited. • Evaluation of high producing Gas Oil Ratio (GOR) wells using gas-lift diagnostics.• Computation of the injected gas allocation factor in dual-string wells when both strings are producing. It was a daunting task to find technology capable of integrating the different data sources and data structures without duplicating information. In addition, the technology has to be smart enough to feed data automatically to the engineering processes and create various well monitoring reports and alarms. This is so that well KPIs (Key Performance Indicators) based on well performance analysis are always available for further diagnosis and analysis to help engineers make informed decisions at the right time.For well performance analysis, a thorough knowledge of reservoir information is essential to determine reservoir deliverability. Not every well has complete reservoir information available. A composite IPR is built at the solution node where fluid from all producing layers is commingled. This helps to manage uncertainty on the reservoir side in multiple completion wells. In high producing GOR wells, a well-model based gas-lift diagnostic technique is used to correct GOR value analyzing the gas-lift performance (GLP) curve and thus helps to optimize the gas injection rate in the well and improves the well performance. Also, in dual-string wells, the gas-lift injection allocation factor is a key element of the gaslift optimization (GLO) process as both strings have a common gas injection source (i.e. common annulus). A method is developed to compute the gas injection rate in each string, based on well tests, to determine the gas-lift injection allocation factor. Currently, this well model based method is being tested and reviewed prior to full implementation in the field.Additionally, a well-model based Virtual Metering (VM) workflow is developed to estimate daily production rates in the absence of daily flow measurements. Models are validated using the sporadic well test and both Static Gradient Survey (SGS) and Flowing Gradient Survey (FGS). Valid models are used to predict the well performance on a daily and monthly basis which ensures effective well and field monitoring and surveillance processes.

Losses while drilling are a serious concern to oilfield industry. Loss of expensive drilling fluid increases the overall cost of the well. Rig time spent curing the losses can represent significant cost overruns for the well. In extreme cases well control may become an issue. The general practice to control losses starts from diagnosis of the cause. The common solutions to manage the loss circulation problem include drilling fluid treatments involving decreasing the density, controlling the viscosity and addition of lost circulation materials (LCM), controlling the drilling parameters, and placement of cement plugs. This paper will discuss the treatment of drilling fluid with Advanced Engineered Fiber (AEF), the mechanism of action of AEF and its successful application as a solution for lost circulation in Pakistan. Introduction Lost circulation is a common problem encountered during drilling. This problem can result from minor to extremely expensive and dangerous situations. The severity and persistence of a lost circulation problem are determined by the type of formation to which fluid is being lost. Generally lost circulation can occur in cavernous or vugular formations, highly permeable zones and fractured (natural or induced) formations. OMV in Pakistan had serious lost circulation problems in the Sawan field while drilling the Sui Main Limestone (SML) and Ranikot formations. Geologically Sui Main Limestone and Ranikot formations are fractured lime stones interlayered with thin beds of sand stone and clay stone respectively. Furthermore it is hard to reduce drilling fluid density below 8.9 lbm/gal due to stability problems of the Ghazij shale overlain SML Stone (fig-1) Losses in this area could range anywhere from 3,000 bbl of mud per well in the SML formation. While drilling the Sawan-3 well more than 20,000 bbl of drilling fluid were lost and the rig spent 8 days fighting the losses using all the conventional LCM available on the rig. Three cement plugs were required to control losses and completed the well after the unsuccessful LCM treatments. Table -1 shows the volume of drilling fluid lost in some off set wells in the area. Depending on the severity of the problem several techniques and products are available, the most common technique is to pump a high concentration LCM pill with fibers, flakes or granules, alone or in combination. Indeed, the pill pumped can fail and be lost to the formation if the LCM particles are smaller than 1/3 of the pore size or fracture width in the thief zone. The LCM's effectiveness is influenced by the material type, particle size distribution and optimum concentration determined by the lost circulation scenario (pore size or fracture width).To control losses into a rock matrix, the drilling fluid must contain some particles that are at least one-third as large as the flow path.

In a challenging well in a mature gas field offshore Germany, four different size liners with annular clearance of less than 1-in. with the open hole or previous casing were cemented. Successful cementing of these liners was critical in order to drill and complete the well before putting it into production. To avoid lost circulation during cementing, we established loss-free mud circulation rates before the cementing operation and designed cement slurries with long thickening times for placement at low rates. Additionally, we used fibers in the cement slurry, and pumped treated micronized barite drilling fluid ahead of the cement slurry to lower friction pressures and optimize mud removal. We validated cement slurry designs through a rigorous laboratory testing procedure, including go/no-go procedures in the high temperature/high pressure (HPHT) consistometer. Long thickening times were needed, especially on a 600 m long 6-in. expandable liner cement job. We tested the setting times of cement accurately with ultrasonic cement analysis and static gel strength analysis devices. Additives to reduce the risk of gas migration were included in all cement slurries. In order to optimize mud removal and reduce the chance of cement slurry getting contaminated, custom made centralizers were strategically placed in highly critical areas. We optimized spacers through a full laboratory analysis of compatibility between spacer and the low-toxic oil based mud, as well as performing reverse emulsion and grid tests. We validated the mud removal design with 2-D simulations to predict the effectiveness of mud displacement from the wellbore. Cement slurry was placed without losses on all liners. In all cases, we had positive indications that cement slurry reached up to the liner hanger by observing cement slurry in the returns back to surface. All formation integrity tests on the liner shoe were successful and allowed drilling of the consecutive section. The final production liner was logged using a radial bond tool and advanced cement evaluation processing was run on the data in order to better evaluate cement quality. Good cement bond quality was observed behind the production liner.

The job objective in a UK North Sea field was to permanently abandon a well that had poor cement bonding behind the casing across the intended isolation intervals. The challenge was to provide lateral isolation across two separate intervals in the most efficient way possible. Two "perf-and-wash" operations were executed successfully during the well abandonment. The deeper barrier envelope was validated by tagging and pressure testing the plug. The shallower section had been logged prior to the operation and, on completion of the perf-and-wash job, the plug was drilled out to allow for relogging, which indicated more than 76% of the perforated interval had circumferential coverage. After the bond log results were confirmed, a further cement plug was set across the shallow interval by conventional methods and verified by tagging and pressure testing. This paper outlines the detailed design preparations and presents both case histories where these steps were implemented successfully.