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Bentonite is not typically used as the primary fluid-loss agent in normal-density slurries. In low-density slurries, where higher concentrations can be used, it may provide sufficient fluid-loss control (400 to 700 cm 3 /30 min) for safe placement in noncritical well applications. Fluid-loss control, obtained through the use of bentonite, is achieved by the reduction of filter-cake permeability by pore-throat bridging. Microsilica imparts a degree of fluid-loss control to cement slurries because of its small particle size of less than 5 microns. The small particles reduce the pore-throat volume within the cement matrix through a tighter packing arrangement, resulting in a reduction of filter-cake permeability.
Accelerators speed up or shorten the reaction time required for a cement slurry to become a hardened mass. In the case of oilfield cement slurries, this indicates a reduction in thickening time and/or an increase in the rate of compressive-strength development of the slurry. Acceleration is particularly beneficial in cases where a low-density (e.g., high-water-content) cement slurry is required or where low-temperature formations are encountered. Of the chloride salts, CaCl2 is the most widely used, and in most applications, it is also the most economical. The exception is when water-soluble polymers such as fluid-loss-control agents are used.
Over the years, attempts have been made to track the working history of coiled tubing (CT) strings in service to maximize the service utility of the tube while minimizing fatigue failures. As a result, three commonly used methodologies for predicting the fatigue condition of the CT were developed. A relatively simplistic approach used to predict the working life of coil tubing is commonly described as the "running-feet" method, in which the footage of tubing deployed into a wellbore is recorded for each job performed. This deployed footage is then added to the existing record of footage deployed in service for any given string. Depending upon the service environment, type of commonly performed services, and local field history, the CT string is retired when the total number of running feet reaches a predetermined amount.
Introduction Any unintended impedance to the flow of fluids into or out of a wellbore is referred to as formation damage. This broad definition of formation damage includes flow restrictions caused by a reduction in permeability in the near-wellbore region, changes in relative permeability to the hydrocarbon phase, and unintended flow restrictions in the completion itself. Flow restrictions in the tubing or those imposed by the well partially penetrating a reservoir or other aspects of the completion geometry are not included in this definition because, although they may impede flow, they either have been put in place by design to serve a specific purpose or do not show up in typical measures of formation damage such as skin. Over the last five decades, a great deal of attention has been paid to formation damage issues for two primary reasons: (1) the ability to recover fluids from the reservoir is affected very strongly by the hydrocarbon permeability in the near-wellbore region, and (2) although we do not have the ability to control reservoir rock properties and fluid properties, we have some degree of control over drilling, completion, and production operations. Thus, we can make operational changes, minimize the extent of formation damage induced in and around the wellbore, and have a substantial impact on hydrocarbon production. Being aware of the formation damage implications of various drilling, completion, and production operations can help in substantially reducing formation damage and enhancing the ability of the well to produce fluids. On this page, we discuss methods to measure and to quantify the extent of formation damage and provide criteria that can be used to identify various types of formation damage. The goal is to define the mechanisms involved better so that an operator can recommend and design the correct remedial action and/or make changes to drilling, completion, and production operations to minimize damage in the future. It is generally true that, whenever possible, preventing formation damage is more effective than remedial treatments such as acidizing and fracturing. We do not discuss such treatments in this chapter. However, for each type of damage mechanism, potential remedial treatments are suggested. It is evident that, to quantify formation damage and to study its impact on hydrocarbon production, one must have reasonable estimates of the flow efficiency or skin factor. Several methods have been proposed to evaluate these quantities for oil and gas wells.
Drilling at remote sites, such as artificial islands, comes with challenges, not least of which is drilling-waste management. Drill cuttings, generated from the wellbore during drilling, traditionally are the focus of attention, and a solution is available to treat this waste stream at source. In many projects, however, slop waste and, in some cases, conductor drilling waste is also generated. Until now, no one process has been able to treat these two additional waste streams at source. Adopting traditional waste treatment methods for these waste streams at a remote site could increase project overheads by more than 200%, vs. a conventional wellsite.
Abstract During drilling of permeable reservoirs, drilling fluid may penetrate the formation and induce damage to the reservoir rock. Specifically, solids present in the drilling fluid may enter the formation and cause subsequent reduction in reservoir permeability in the area near the wellbore. When drilling with a water-based drilling fluid in a reservoir, various polymer-based additives are normally applied to reduce the filtration loss. These additives, such as Xanthan Gum, Poly Anionic Cellulose (PAC) and Starch may help in reducing losses to the formation in presence of small pore-throats and low differential pressures. If the pore throats exceed e.g. 20μm and differential pressures reach 500psi, these additives have little effect on reducing loss of drilling fluid to the formation and thereby little effect in preventing solids from entering the formation. Lost circulation is particularly challenging when losses occur in the reservoir section. This is because LCM treatment may create formation damages. Green et al. (SPE-185889) showed the nature of drilling fluid invasion, clean-up, and retention during reservoir formation drilling. They also showed the lack of direct relation between fluid loss and formation damage. In light of such ideas, a development of new Non-Invasive Fluid (NIF) additives was conducted. These additives were able to handle downhole pressure differences and create a preventative sealing of a permeable formation when applied into a solids-free drilling fluid. Ceramic discs of various permeability and mean pore-throat size were installed into a HTHP pressure cell. Drilling fluid was pumped through the cell and a filter cake was formed across the ceramic disc. A pressure of 500psi was applied and filtration loss was measured over a 30-minute period. Examples are herein presented showing how filter cake materials were applied into the drilling fluid and effectively sealing the permeable surface of the ceramic disc. Also, it will be shown how the filter cake was effectively removed from the discs using a breaker solution. Furthermore, a selection of experiments is presented, showing the possibility to heal lost circulation in permeable reservoirs without the presence of weighing materials, clays or drill-solids in the drilling fluid. A test was also conducted in such a way that the disc was fractured inside the test cell to investigate the impact on fluid loss.
Abstract On a Deep Gas Project in the Middle East, it is required to drill 3500 ft of 8-3/8" deviated section and land the well across highly interbedded and abrasive sandstone formations with compressive strength of 15 - 35 kpsi. While drilling this section, the drill string was constantly stalling and as such could not optimize drilling parameters. Due to the resulting low ROP, it was necessary to optimize the Drill string in order to enhance performance. Performed dynamic BHA modelling which showed current drill string was not optimized for drilling long curved sections. Simulation showed high buckling levels across the 4" drill pipe and not all the weight applied on surface was transmitted to the bit. The drilling torque, flowrate and standpipe pressures were limited by the 4" drill pipe. This impacted the ROP and overall drilling performance. Proposed to replace the 4" drill pipe with 5-1/2" drill pipe. Ran the simulations and the model predicted improved drill string stability, better transmission of weights to the bit and increased ROP. One well was assigned for the implementation. Ran the optimized BHA solution, able to apply the maximum surface weight on bit recommended by the bit manufacturer, while drilling did not observe string stalling or erratic torque. There was also low levels of shocks and vibrations and stick-slip. Doubled the on-bottom ROP while drilling this section with the same bit. Unlike wells drilled with the previous BHA, on this run, observed high BHA stability while drilling, hole was in great shape while POOH to the shoe after drilling the section, there were no tight spots recorded while tripping and this resulted in the elimination of the planned wiper trip. Decision taken to perform open hole logging operation on cable and subsequently run 7-in liner without performing a reaming trip. This BHA has been adopted on the Project and subsequent wells drilled with this single string showed similar performance. This solution has led to average savings of approximately 120 hours per well drilled subsequently on this field. This consist of 80 hours due to improved ROP, 10 hrs due to the elimination of wiper trip and a further 30 hrs from optimized logging operation on cable. In addition, wells are now delivered earlier due to this innovative solution. This paper will show how simple changes in drill string design can lead to huge savings in this current climate where there is a constant push for reduction in well times, well costs and improved well delivery. It will explain the step-by-step process that was followed prior to implementing this innovative solution.
Abstract Drilling is probably the most critical, complex, and costly operation in the oil and gas industry and unfortunately, errors made during the activities related are very expensive. Therefore, inefficient drilling activities such as connection duration outside of optimal times can have a considerable financial impact, so there is always a need to improve drilling efficiency. It is for this fact, that the measure of different behaviors and the duration of the drilling activities represent a significant opportunity in order to maximize the cost saving per well or campaign. Reducing the cost impact and maximizing the drilling efficiency are defined by the way used to calculate the perfect well time by the technical limit, non-productive time (NPT), and invisible lost time (ILT), in an operating company drilling plan. Different approaches to measure the invisible lost time that could be present in the in slips activity on the drilling operation are compared. Results show the differences between multiple techniques applied in real environments coming from a cloud platform. The methodologies implemented are based on the following scenarios, the first one use a combination of a custom technical limit based on technical experience, the historical data limit using standard measures (mean, average, quartiles, standard deviation, etc.), and a depth range variable (phases) differentiation, initial, intermediate, and final hole sizes is used. A complexity comparison uses the rig stand and phase footage variables for base line (count and duration) definition per phase, the non-productive time activities exclusion and data replace techniques mixing with an out of standard time detection in slips behavior (motor assemblies, bit replacing, bottom hole assembly (BHA), etc.) using standard and machine learning mechanisms. A final methodology implements an in slip ILT by technical limit definition using machine learning. The results using the same data set (set of wells) and coming from the different methods has been evaluated according to the total invisible lost time calculated per phase, percentage of activities evaluated with invisible lost time per phase and the variation of ILT considering the activities defining the technical limit. Finally, the potential implementation by any operator can be evaluated for these methodologies according to their specific requirements. This analysis creates a guideline to operating companies about multiple techniques to calculate ILT, some using innovative procedures applied on machine learning models.
Abstract The drilling industry faces several challenges related to downhole vibration; amongst the solutions introduced to alleviate those challenges, a unique Axial Agitation System is often considered. This paper qualitatively analyses the effect of the Axial Agitation System in directional drilling and quantifies how it addresses the above challenges observed in Rotary Steerable System (RSS) Bottom Hole Assembly (BHA) used in the 8.5 in. section in different wells of the ADNOC Offshore mature field. The Axial Agitation System consists of Axial Oscillation Tool which generates a pressure pulse from a valve driven by mud flow converted to axial motion by The Shock Tool. The system complements the rotational movement of the string by introducing gentle and consistent axial oscillating motion. The drill string moves around its rotational axis, oscillating along its axial axis reducing kinetic frictional losses from interaction with the wellbore, especially in directional and long lateral sections. The analysis consisted in comparing drilling dynamics metrics between wells with AAS in the drill string and offset wells without it, in the 8.5in hole section. As a pilot project, the system was introduced into Well A. Based on the successful tests in the pilot well; the system was also utilized in Wells B & C. The metrics include, but are not limited to, drilling activities, surface mechanical indicators, downhole data from the RSS as well as mathematical modelled algorithms. The results of the analysis of wells clearly indicate an enhancement into the drilling dynamics in terms of overall reduction in kinetic friction, improved weight transfer, less hanging and levels of torsional dynamics, shocks and vibration. The collateral benefits also included performance improvement, reduced non-productive time (NPT) and lower mechanical specific energy (MSE) to drill the section. The Axial Agitation System complemented very well with the rotary steerable system as well as other BHA components and delivered consistent performance in all three wells. High amplitude fine-tuned Axial Agitation System paired with RSS BHA creates a combination of a highly efficient directional system. The results are consistently performance with reduction in the shock and vibration levels in the environment. This also benefits in improving tool reliability, directional control while also optimizing the repair and maintenance costs for the downhole tools.
Abstract A large operator of a brown field offshore in the middle east has decided to provide full lower Completion accessibility and ensure prevention of open hole collapse as it can lead to various gains throughout the life of the well. Among those benefits, it provides a consolidated well bore for various production logging & stimulation tools to be deployed effectively, as well as full accessibility, conformance control and enable to provide production allocations for each zones. However there are multiple challenges in deploying lower completion liner in drains involving multiple reservoirs and geo steered wells: Well Bore Geometry, dog legs/ tortuosity etc. & differential sticking possibilities and of course the open hole friction. Due to the size of the open hole, restricted casing design and utilization of limited OD pipes further add to the complications of deploying the Lower completion liner in such brown Field wells. This paper intend to review the multi-step methodology approach implemented in recent years by the company to effectively deploy 4-1/2" Liner in 6" Horizontal Open Hole section. Among the techniques used to assist successful deployment of lower completions are: Improving hole cleaning, ensure smooth well bore with the use of directional drilling BHA, reduction of the Open Hole friction by utilizing Lubricated brines, fit for purpose Centralizers, use of drill pipe swivel devices to increase weight available to push the liner & reduce buckling tendency. With the length of open hole laterals reaching up to 10,000 ft for 6" Lower drains, open hole drag, friction & cleanliness are major components that causes challenges in deploying the Liner till TD. The use of specially formulated brines with fixed percentage of lubricants proved to significant reduce friction compared to the drilling mud used for drilling the horizontal drain. The combination of low friction brine with proper centralization / standoff which resulted in reduced contact area with the formation has also shown good results in preventing differentials sticking while running the liner through multilayer reservoirs having significantly different reservoir pressures. Another major constrain to deploy the lower completion liner in this offshore field is the very nature of the wells being primarily workover. This involves generally Tie back liners run to shallow depths to restore the integrity of wells. This limits our ability in the selection of drill pipe that can be used as only smaller OD drill pipes and HWDP can be utilized in order to deploy the Liner to bottom. On many occasions this provides only limited weight to push the Liner down to TD and impact our ability to set the liner top packer. Drill pipe rotating swivel devices have been utilized to improve our weight availability & transferability to push the liner down and to set the liner top packers. In order to provide independent deactivation mechanism for the drill pipe swivel and to have complete success in our liner deployments, a dedicated ball activated sub was designed to deactivate the swivel acting as back up in case primary deactivation methods fails during liner setting. The combined use of all these techniques enabled the company to deploy 4.5" Liners in 6" Horizontal drains with high success in this offshore Brown Oil field of UAE. This resulted in better well construction and complete access to lower drains over the life of the wells.