Flow Simulation and Influence Factors Analysis of CO2 Foam Fracturing in Annulus Injection

CO2 foam fracturing fluid is widely used in unconventional oil and gas production because of its easy flowback and low damage to the reservoir. Nowadays, the fracturing process of CO2 foam fracturing fluid injected by coiled tubing is widely used. However, the small diameter of coiled tubing will cause a large frictional pressure loss in the process of fluid flow, which is not beneficial to the development of fracturing construction. In this paper, the temperature and pressure calculation model of gas, liquid, and solid three-phase fluid flow in the wellbore under annulus injection is established. The model accuracy is verified by comparing the calculation results with the existing gas, solid, and gas and liquid two-phase model of CO2 fracturing. The calculation case of this paper shows that compared with the tubing injection method, the annulus injection of CO2 foam fracturing fluid reduces the friction by 3.06 MPa, and increases the wellbore pressure and temperature by 3.06 MPa and 5.77°C, respectively. Increasing the injection temperature, proppant volumetric concentration, and foam quality will increase the wellbore fluid temperature and make the CO2 transition to the supercritical state while increasing the mass flow rate will do the opposite. The research results verify the feasibility of the annulus injection of CO2 foam fracturing fluid and provide a reference for the improvement of CO2 foam fracturing technology in the field.

Worlds First Offshore Horizontal Well Using Jointed Pipe Cemented Frac Sleeve Technology

The Valdemar field, located in the Danish sector of the North Sea, targets a Lower Cretaceous, "dirty chalk" reservoir characterized by low permeabilities of <0.5mD, high porosities of >20% and contains up to 25% insoluble fines. To produce economically the reservoir must be stimulated. Typically, this is by means of hydraulic fracturing. A traditional propped fracture consists of 500,000 to 1,000,000 lbs of 20/40 sand, placed using a crosslinked seawater-based borate fluid. The existing wells in the field are completed using the PSI (perforate, isolate, stimulate)1 system. This system was developed in the late 1980s as a way of improving completion times allowing each interval to be perforated, stimulated and isolated in a single trip and has been used extensively in the Danish North Sea in a variety of fields. The system consists of multiset packers with sliding sleeves and typically takes 2-3 days between the start of one fracture to the next. Future developments in this area now require a new, novel and more efficient approach owing to new target reservoir being of a thinner and poorer quality. In order for these new developments to be economical an approach was required to allow for longer wells to be drilled and completed allowing better reservoir connectivity whilst at the same time reducing the completion time, and therefore rig time and overall cost. A project team was put together to develop a system that could be used in an offshore environment that would satisfy the above criteria, allowing wells to be drilled out to 21,000ft and beyond in excess of coiled tubing reach. The technology developed consists of cemented frac sleeves, operated with jointed pipe, allowing multiple zones to be stimulated in one trip, as well as utilizing a modified BHA that allows for the treatments to take place through the tubing, bringing numerous benefits. The following paper details the reasons for developing the new technology, the development process itself, the challenges that had to be overcome and a case history on the execution of the first job of its kind in the North Sea, in which over 7MM lbs of sand was pumped successfully, as well as the post treatment operations which included a proof of concept in utilizing a tractor to manipulate the sleeves. Finally, the production performance will be discussed supported by the use of tracer subs at each of the zones.

Enhancements in Fracturing Fluid Engineering Reawakens a North Sea Giant

The Valhall field, operated by AkerBP, has been a major hub in the North Sea, on stream for thirty-eight years and recently passed one billion barrels of oil produced. The field requires stimulation for economical production. Mechanically strong formations are acid stimulated, while weaker formations require large tip-screenout design proppant fractures. Fracture deployment methods on Valhall have remained relatively unchanged since the nineties and are currently referred to as "conventional". Those consist in a sequence of placing a proppant frac, cleaning out the well with coiled tubing, opening a sleeve or shooting perforations, then coil pulling out of hole pumping the proppant frac. For the past few years, AkerBP and their service partners have worked on qualifying an adapted version of the annular coiled tubing fracturing practice for the offshore infrastructure - a first for the industry, which has been a strategic priority for the operator as it significantly reduces execution time and accelerates production. As with all technology trials, the implementation of this practice on Valhall had to begin on a learning curve through various forms of challenges. Whilst investigating the cause and frequency of premature screenouts during the initial implementation of annular fracturing, the team decided to challenge the conventional standards for fluid testing and quality control. Carefully engineered adjustments were made with regards to high shear testing conditions, temperature modelling, and mixing sequences, these did not only identify the root cause for the unexpected screenouts, but also helped create the current blueprint for engineering a robust fluid. Since the deployment of the redefined recipe, adjusted testing procedures and changes made to the stimulation vessel, there have not been any cases of fluid induced screenouts during the executions. The fewer types of additives now required for the recipe have lowered the cost of treatments and the lower gel loading leads to reduced damage in the fractures, thereby contributing to enhanced production over the lifetime of the wells. This paper describes the investigation, findings and the resulting changes made to the fluid formulation and quality control procedures to accommodate for high shear and dynamic wellbore temperature conditions. It discusses the rationale behind the "reality" testing model and, proves that significant value is created from investing time in thoroughly understanding fluid behaviour in the lab, prior to pumping it on large-scale capital-intensive operations. The study demonstrated that there is always value in innovating or challenging pre-conceived practices, and the learnings from this investigation significantly improved the track record for annular fracturing on Valhall, redefined fluid engineering for the North Sea and will inform future annular fracturing deployments on other offshore assets around the world.

Fluorescent Microspheres Method Efficiency in Horizontal Wells with Gas Condensate Liquid

The proportion of hard-to-recover reserves is currently increasing and reached more than 65% of total conventional hydrocarbon reserves. This results in an increasing number of horizontal wells put into operation. When evaluating the resource recovery efficiency in horizontal wells, and, consequently, the effectiveness of the development of gas condensate field, the key task is to evaluate the well productivity. To accomplish this task, it is necessary to obtain the reservoir fluid production profile for each interval. Conventional well logging methods with proven efficiency in vertical wells, in case of horizontal wells, will require costly asset-heavy applications such as coiled tubing, downhole tractors conveying well logging tools, and Y-tool bypass systems if pump is used. In addition, the logging data interpretation in the case of horizontal wells is less reliable due to the multiphase flow and variations of the fluid flow rate. The fluorescent-based nanomaterial production profiling surveillance technology can be used as a viable solution to this problem, which enables cheaper and more effective means of the development of hard-to-recover reserves. This technology assumes that tracers are placed downhole in various forms, such as marker tapes for lower completions, markers in the polymer coating of the proppant used for multi-stage hydraulic fracturing, and markers placed as fluid in fracturing fluid during hydraulic fracturing or acid stimulation during bottom-hole treatment. The fundamental difference between nanomaterial tracers production profiling and traditional logging methods is that the former offers the possibility to monitor the production at frac ports in the well for a long period of time with far less equipment and manpower, reduced costs, and improved HSE.

Performance of 15 Years of Hydraulic Fracturing of Oil Wells in South of Oman

The first application of Hydraulic Fracturing in the South Oman started in 2000 to enhance water disposal wells. In 2004 the first oil wells were frac'ed. Although the technology was deployed many times, it never grew into a conventional practice. From 2004 to 2017 on average 5 Oil Wells were hydraulically fractured on yearly basis. In November 2017, a Hydraulic Fracturing Maturation & Expansion Workshop was conducted with the vision of growing the application by applying new frac concepts. A focused effort was initiated to drastically reduce cost, and simultaneously increase the scope by executing larger frac campaigns. The first hydraulic fracturing campaign introducing the frac new concepts, started end 2018 and a rapid growth from 5 wells per year to 45 wells per year was anticipated in the next three years. This large growth of scope relied on a steady supply of frac candidates and needed to be supported by screening and selecting processes that are fit for purpose in finding candidates. Although more than a hundred wells had already been frac'ed wells, selection of the most appropriate wells for stimulation was and remains one of the greatest challenges. A frac performance database was created for over 100 wells that had been hydraulically fracture stimulated to date. Recognizing that the frac performance depends on many variables ranging from subsurface properties to surface execution of the frac job, the size of the dataset proved to be too small to find correlations using sophisticated multivariable regression methods. Instead, the dataset was analyzed through careful investigation and evaluation of each frac job. In this paper the net oil gain will be used as the key success criteria i.e., value driver to demonstrates how effective the frac is achieving its business objective. Some 40% of the producers had been producing from the same zone before the hydraulic fracture stimulation. This provided the opportunity to understand the efficiency of the stimulation in terms of the "stimulation ratio" i.e., measuring the net oil gain. This paper will focus on investigating the suitability of frac'ing the reservoir based on the initial production variables; Gross Rate and BS&W. Also, this paper will discuss benefits and impacts of Hoist versus Coiled-Tubing clean-out on the frac delivery process and compare the frac performance. To date, the project demonstrated that hydraulic fracturing at low cost, can be applied as a viable development concept for producing oil wells, with the potential unlock additional and new reserves. Significant folds in production increase are possible from 2x to 7x.

The Use of Hydraulic Completion Snubbing Units HCU in Long Laterals in U.S. Shale Plays

Coiled tubing units (CTU) have been used to drill-out frac plugs in shorter horizontal shale wells for the last decade, but coil has mechanical limitations. The new innovative technology of Hydraulic Completion Snubbing Units (HCU) is gaining popularity across North and South America to drill-out frac plugs in long lateral, high-pressure, and multi-well pads. The HCU is designed for drill-outs and interventions where coil may not be the best option. This paper will summarize the recent evolution of the HCU system. Case histories will be provided from the Appalachian and Permian shale plays. The latest HCU consists of a stand-alone unit that mounts on the wellhead after completion. The primary components include the jack assembly, a gin pole, traveling/stationary slips, a redundant series of primary/secondary blowout preventers, a rotary table, power tongs, and an equalize/bleed off loop. Tubing up to 5 ½" is used to carry a downhole motor, dual back pressure values, and the drill bit. Slickwater is used for the drilling fluid to carry out parts from the frac plugs while the tubing is rotated via the jack rotary table. Torque and drag modeling are performed to guide downhole expectations that allow most wells to be drilled in one trip and with one bit without short trips back to the heel or bottom- hole vibration assembly tools. Finally, a remote telemetry data acquisition system has been added that summarizes the drilling data and key performance indicators. In 2016, a North American operator drilled and completed the first super lateral in the Appalachian Basin, setting the completed lateral record at over 18,500 ft. Since then, many operators have been routinely drilling laterals between 12,000 ft and 16,000 ft. HCU technology has been used in the longest laterals in onshore North America, including the lower 48 U.S records for completed lateral length (LL) at 20,800 ft and the total measured depth (MD) record at 30,677 ft. The average lateral contains between 60 to 90 plugs and can be drilled out in 3.5 to 4.5 days. The record number of plugs drilled out by an HCU is 144 and took 5.2 days. High-pressure wells are also routinely encountered where pressures range from 3000 to 8000 psi during operations. Operators are achieving faster drilling times per plug, less chemical usage, faster moves between wells, and running tubing immediately after the drill-out, thus eliminating the need for a service rig. Operator's desire to reach total depth with the least risk and as cost-efficiently as possible resulted in the HCU gaining market acceptance. This paper will showcase the novel evolution of the HCU system that has enabled it to be a safe and effective option for interventions outside of just frac plug drill-outs such as fishing for stuck/parted coil or wireline and installing production tubing/artificial lift systems.

Hydraulic Fracturing as Game Changer to Maximize Waterflooding Efficiency in a Brownfield

Primary production mechanism of a clean sandstone reservoir in a brownfield for oil production has been recently changed from natural depletion to waterflooding. Despite the apparently moderate petro-physical properties of the formation, injector wells performances were observed to be extremely poor, mainly due to: high drilling-induced formation damage and Fluids interaction within the reservoir (injection across the oil rim section). Several stimulation technologies have been applied to improve wells injection capability for pressure support optimization. Re-perforation via abrasive jetting, perforations wash through coiled tubing and various acid formulations via bullheading were attempted without achieving any significant increase in injectivity. Considering the modest rock permeability, the need to access a wider formation area to improve oil sweep efficiency and the crucial requirement to re-pressurize the reservoir, an additional card was played as last resort: hydraulic fracturing. This technique was not new to the area and already experimented by different operators. Several producer wells in different layers were hydraulic fracturing stimulated with proppant and/or acid in the past with a good rate of success. Why not to try then? Given the past experience on the same field with hydraulic fracturing in oil producers and accounting for well integrity and potential injectivity, one was chosen as suitable candidate. Offset wells hystorical data were used to build a hydraulic fracturing reservoir model and plan for the activity in details; operator and service providers engaged in a Frac Well On Paper activity in order to reduce any margin of error during field operations. An approach that proved successful. From there, the first trial well was planned and performed successfully. 4 other hydraulic fracturing jobs on 4 wells followed at close distance in time with different, but steadily comforting, results. Injection was improved from negligible initial values up to 2000 mc/day for the post-stimulation condition, exceeding the preliminary expectations. This paper introduces the steps taken to start the hydraulic fracturing campaign, the decision process that led to the design of the treatment, an overview of the execution phases, results well by well and lessons learned to optimize future campaigns.

A State-of-the-Art Approach to Unlock the Potential of Complex Sour Reservoirs in Southern Oman During Global Market Downturn

Recent years and especially the coronavirus pandemic have been very challenging for the oil industry, resulting in a significant reduction in investment, forcing companies to review budgets and search for more efficient and economical technologies to achieve the target level of hydrocarbon production and revenue generation. In PDO, one of the most challenging fields is "AS", where extreme downhole conditions require a very well-engineered approach to become economical. This field has already seen some of the most advanced technology trials in PDO that are also covered in multiple SPE papers. Based on the new approaches and techniques that were successfully implemented on recently drilled wells, it was decided to review the older, previously fractured wells in the area and assess them for a refracturing opportunity. The main challenge in this project was that these older wells were previously hydraulically fractured in multiple target intervals, therefore both zonal isolation and successful placement of the new fracs were becoming the major concerns. As the planned coverage by the new fractures was to ensure no bypassed pay, the only applicable technology on the market was a pinpoint fracturing process, whereby the targeted placement is achieved through limited entry perforations and focused energy of the injected fluid. The subject pinpoint technology anticipates that the limited entry sandblasting perforation is created and then proppant laden fluid is pumped through a sandblasting nozzle which is part of either a coiled tubing (CT) or a jointed pipe (JP) Bottom Hole Assembly (BHA), and the backside (or the annulus of the injection path) is used to maintain the positive backpressure from the top. This technology allows for choosing a desirable order of target interval selection inside the well, unlike conventional plug and perf or a simplified multistage completion, where the treatments must be placed only in order from bottom to top. Another advantage of this approach is a faster frac cycle through the elimination of wellbore cleanout requirement. Being a unique and first-ever application in the Middle East, using CT for placing frac treatments through a jetting nozzle demonstrates the full scale potential of this approach not only in conventional wells but also in complex, sour and High Pressure (HP) environments that are often found in the Sultanate of Oman and in the Middle East. This paper will cover the advantages and disadvantages, complexity and requirements, opportunities and lessons learnt in relation to this approach.

Successful Remediation of Sustained Casing Pressures in Gas Cap Injector Wells with the Use of Flexible and Self Healing System

Several injection wells in Prudhoe Bay, Alaska exhibit sustained casing pressure (SCP) between the production tubing and the inner casing. The diagnostics on these wells have shown communication due to issues with casing leaks. Conventional cement systems have historically been used in coiled-tubing-delivered squeeze jobs to repair the leaks. However, even when these squeeze jobs are executed successfully, there is no guarantee in the short or long term that the annular communication is repaired. Many of these injector wells develop SCP in the range of 300-400 psi post-repair. It has been observed that the SCP development can reoccur immediately after annulus communication repair, or months to years after an injector well is put back on injection. Once SCP is developed the well cannot be operated further. A new generation of cement system was used to overcome the remedial challenge presented in these injector wells. This document provides the successful application of a specialized adaptive cement system conveyed to the problematic zone with the advantage of using coiled tubing equipment for optimum delivery of the remedial treatment.