Albert, Larry (Allied-Horizontal Wireline Services) | Booher, Jason (Allied-Horizontal Wireline Services) | Wilson, Anthony (Allied-Horizontal Wireline Services) | Hamilton, Fraser (Impact Selector International) | Hradecky, Jason (Impact Selector International) | Dunning, Dustin (Wireco WorldGroup) | Pratosov, Vadim (Wireco WorldGroup)
An E&P operator was developing a reservoir and planned a horizontal well in an area where zones above the target cause drilling problems when trying to build angle and land the horizontal lateral. The operator suffered drilling difficulties on offset wells; therefore, it was decided to change the drilling plan for this prospect. The new plan required drilling through the target reservoir, into the formations below and then drill back up dip to the target. After reaching the base at a measured depth of 14,000 ft. the well plan required drilling up at maximum of 114° until reentering the target reservoir. Because of faulting in the area and required well direction, the target reservoir was dipping up at ∼10° laterally in the direction of the horizontal drilling target. To maintain position in the reservoir, the well had to drilled at ∼100° deviation to a measured depth of 21,100 ft.
This wellbore trajectory made normal wireline plug and perforating completion operations extremely difficult. The wellbore trajectory meant high frictions on the wireline when coming off bottom. Also, due to the toe-up trajectory there was risk the wireline tools would slide down the inclined casing during and after plug setting and perforating. If the tool position could not be maintained there was risk the wireline cable could be entangled and a stuck tool could result. If the tools overrun the wireline cable the result could be wireline cable next to the perforating guns when detonated and wireline cable severed. The E&P operator needed to know if this challenge could be met.
Alternatives to pump down plug and perforating could be very expensive (estimated $millions): Abandon acreage, Continue drilling attempts building angle above the target, Reposition surface location and drill down dip, Reduce angle and shorten lateral in target, or Coiled tubing conveyed plug and perforating completion.
Continue drilling attempts building angle above the target,
Reposition surface location and drill down dip,
Reduce angle and shorten lateral in target, or
Coiled tubing conveyed plug and perforating completion.
To meet the challenge several new methods and technologies developed for extended laterals were utilized. These products and methods included: advanced risk deployment modeling, jacketed wireline cable, addressable separation tool and downhole tension tool.
Operators continue their quest to better understand and design completion strategies to maximize reservoir contact and optimize well spacing. This paper presents a case study that analyzes completion design effectiveness, using pressure data acquired from isolated monitor stages on offset wells during treatment of adjacent wells. The method was employed on three wells of a seven-well pad in the Marcellus, to assess fracture growth and evaluate the performance of employing intra-stage and inter-stage diversion.
Poromechanically-induced pressure responses on isolated monitor stages on offset wells during treatment of an adjacent well, are compared to a fully coupled, three-dimensional, finite element effective stress model, to calculate dominant fracture geometries that correspond to the pressure response induced in the rock. The initiation points and ascending magnitudes of the responses approaching the isolated monitor stage qualify the performance of inter-stage diversion, whereas the fracture growth trends and geometries speak for the efficacy of the intra-stage diversion and overall stage design.
The first well utilized inter-stage diversion and dissolvable plugs to isolate stages; the second well utilized intra-stage diversion to improve cluster efficiency with regular frac plugs for zonal isolation; and, the third well employed regular frac plugs with no use of diversion. This presented a unique opportunity to compare and analyze the fracture growth rates, trends, and geometries, while applying inter-stage diversion and frac plug completion designs for zonal isolation on the same pad.
This paper is a comparative study to understand the value of using inter-stage diversion, along with dissolvable plugs in place of composite frac plugs, after every stage to attain zonal isolation. In addition, completed stages utilized different fluid designs, providing the opportunity to analyze the impact of fluid design on fracture growth trends and diverter performance. The results are interpreted using pressure data-derived fracture maps with production data, which point to the performance of various completion strategies, using an entirely new diagnostic method.
Pre-set or off-depth composite plugs can cause significant non-productive time for a well operator. In the past, fracturing operations using a composite frac or bridge plug that has been pre-set or set off depth required a coiled tubing unit or workover rig to drill the plug out. Then, the well operator could resume the fracturing job or access the wellbore below the plug. However, as this paper demonstrates, composite plug milling via wireline using a tractor and a tractor-based milling tool is a faster, safer, and more cost-effective solution.
In a shale well located in the northern panhandle of West Virginia, a composite frac plug was set off- depth. Prior to mobilizing the tractor-based solution to location, the operator attempted pumping approximately 60,000 pounds of sand to sand-cut the off-depth frac plug out of the well. The sand cutting, though, did not work because perforations above the frac plug took the sand. Other tubing-based solutions required more mobilization time and complex logistics for rigging down and/or moving equipment on location. Therefore, the operator chose a wireline-based method for ease of operation, reduced HSE risk, and cost savings.
The tractor took 50 minutes to drive down 1718 ft in the lateral to the plug. The milling tool milled the top slips on the frac plug in approximately nine hours, and the tractor then pushed the plug 222 ft downhole on top of the previous frac plug. The total time rigged up on the well was 14 hours, and the total time on location was 18 hours. Although this wireline-based plug-milling method takes several hours to mill a plug, the rig-up and execution is simpler than conventional methods, and associated HSE risks on the wellsite are greatly reduced.
The ability to effectively release plugs via wireline provides well operators with another option to complete their objectives, especially when tubing-based methods often take many days or weeks to mobilize at substantial cost to operators.
Khedr, Sherine (BP Exploration Operating Co) | El-dabi, Fady (BP Exploration Operating Co) | Nashaat, Mohamed (BP Exploration Operating Co) | Mohiuldin, Ghulam (BP Exploration Operating Co) | Galal, Alaa (BP Exploration Operating Co) | Slim, Teddy (BP Exploration Operating Co) | Hughes, Andrea (BP Exploration Operating Co) | Morris, Lyndsay (BP Exploration Operating Co) | Ramsay, David (BP Exploration Operating Co) | El-wakeel, Wael (BP Exploration Operating Co) | Mubarak, Hussein (BP Exploration Operating Co) | Smith, Jeffrey (BP Exploration Operating Co) | Munger, Robert (BP Exploration Operating Co)
Giza Fayoum Completions was the second campaign of the West Nile Delta project. The campaign consisted of eight cased-hole gravel pack subsea wells. The Giza Fayoum campaign was sanctioned in August 2017 with an execution start date five months later. In this time, the well designs were finalized, downhole completion equipment manufactured, and the execution plan approved. A high rate water pack sand control technique was designed to deliver an estimated production rate of 120 MMscf/d / well. It was planned to deliver eight wells over a period of 5 months from Q1 2018 giving an average of two and a half weeks per well. Seven of the eight wells were cleaned up through a large bore completion landing string system. Each well was flowed to high rate temporary well test equipment installed on the DP semi-submersible rig to a gas rate of 65 MMscf/d, with PLT logs conducted.
This successful, fast-paced campaign is the result of applying lessons learned from the former campaign; Taurus Libra and identifying additional efficiencies that would improve performance. The design similarities between the two campaigns permitted the team to extend the learning curve and deliver superb performance on Giza Fayoum.
As for safety performance, the campaign was delivered without any lost time incident. A rigorous approach to continuous improvement resulted in reducing the completion time to 12 days per well (not including rig move, de-suspension and suspension activities). The optimized bean up procedures supported by PLT data made it possible to reduce greenhouse emissions by 20%. The sand control technique resulted in a significant reduction of total skins. Moreover, the team succeeded in delivering the wells safely, ahead of plan and under budget while adhering to BP's overarching strategy of delivering safe, compliant and reliable wells.
The efficiencies, safety culture and technology used during this campaign are now being set as the standard for future campaigns in Egypt and beyond.
This paper demonstrates how 280ft of oil column spread unevenly across multiple and differentially depleted reservoir units separated by shale layers of varying thicknesses in a highly deviated (62 deg.) well was perforated in a one trip system and how the project cost was minimized by achieving multiple perforations in a single trip whilst retaining capacity to effectively cure losses and mitigating post-perforation well control risks. Against the conventional perforation methodology where reservoir units are perforated individually, isolated before carrying out the next perforation in the subsequent reservoir. The one trip system was designed and deployed in one run targeting all the 6 separate carefully selected sand lobes in one run ensuring good standoff from the contact and zonal isolation behind casing. Successful execution was confirmed with all the expected physical outcomes which includes pipe vibration, brine loss as well as inspection of the spent guns. A post perforation noise and production logging also confirmed flow across all planned perforation intervals. Perforation of a highly deviated well in differentially depleted multi-lobed reservoirs present significant operational risks. This paper illustrates how one can safely collapse multiple conventional perforation runs into a single trip with its attendant benefits on cost efficiency, crossflow and well control. This is the first of its kind in the Niger Delta.
Optical fiber flatpacks, which are cable-reinforced plastic-encased fiber bundles used for local temperature and acoustic measurements, can be stressed when near a perforating gun. The fiber itself is floated in metal tubes with gel. Understanding the behavior under severe shock causes the use of potential mitigation schemes. In this work, the flatpack containing optic fibers is simulated for survivability on the casing of a perforating gun system. Using a shock hydrocode in two-dimensions (2D), a flatpack is simulated on the 5 1/2-in. casing of a 3 3/8-in. gun with a 21-g shaped charge. Effects of concrete encasement, clamps, and off-angle shots are considered. The view is in the plane of one shaped charge.
Quantitative results include pressure temporal profiles, velocity profiles, and g acceleration at the fibers. Pressure at the flatpack peak is in the hundreds to thousands of psi, and accelerations peak in the hundreds to thousands of g. Unconfined flatpacks tend to launch from the casing, while confined flatpacks tend to oscillate at their location. Pressure contour models show the shaped charge breaking into multiple pressure pulses. The primary shocks are in front of and behind the charge. Secondary pulses occur off-axis near the base of the charge and from the jet bow shock near the top of the charge. Overall comparative simulation results indicate optimum flatpack location and configuration. Novel mitigation schemes are identified and simulated. A fiber-optic flatpack has been simulated in a zero- degree loaded gun for the first time; this information helped with understanding survivability against shaped charge shocks.
Faster production declines than initially forecast were observed in numerous deep-water assets. These wells were completed as Cased Hole Frac-Pack (CHFP) completions (
Seven key damage mechanisms were identified as forming the basis for PI degradation: 1) off-plane perforation stability, 2) fines migration, 3) fracture conductivity, 4) fracture connectivity, 5) fluid invasion, 6) non-Darcy flow and 7) creep effects. A near wellbore production model incorporating the completion, fracture geometry and reservoir is coupled with a geomechanics model to assess each mechanism. A Design of Experiment setup varies the input ranges associated with each of the seven damage mechanisms. Input parameters for the model are risked and rely on ranges from standard and newly developed well and lab tests. The model assesses well performance and driving mechanisms at different points in time within the production life.
Primarily the study focused on high permeability and highly over pressured reservoirs. For the types of wells/fields assessed in the study, the results indicated three phases of decline based on the interaction between the formation properties, the completion components and the operating parameters. The three phases breakdown into: (1) a pre-rock failure stage where declines are relatively small, (2) an ongoing rock failure stage where declines are rapid and (3) a post failure stage where declines are again moderate. In each of these stages different parameters and damage mechanisms were assessed to be impactful. The workflow was also utilized to match pre and post acidizing treatments. A comparison for varying rock types was included looking at the impact of rock strength and formation permeability on the ranking of the damage mechanisms. The impact of operating parameters such as drawdown can also be assessed with the tool showing that increased drawdowns may not always be beneficial to the long-term production of the well.
The paper presents the underlying drivers for PI Decline for deep-water assets of a specific attribute set. Through accurate representation of reservoir and completion, the workflow highlights the impact and combined impact of different damage mechanisms. The paper also shows a direct link between the mechanical properties (moduli and strength) and boundary conditions (pore pressure and stress) and the well performance and productivity. The workflow provides a methodology by which lab and field tests can be transformed into assessments of future well performance without strictly relying on analogs that may or may not be appropriate.
Use of diverters for altering fluid distribution among created hydraulic fractures in horizontal wells has gained popularity in recent years, both for initial and re-fracturing treatments. Aims in initial fracturing treatments have included creating more uniform distribution of slurry within the created fractures, increasing stage efficiency by reducing the number of pumping stages while increasing the number of clusters per stage, increasing the number of fractures created in openhole completions, reducing interactions between fractures in adjacent horizontal wells, etc. In re-fracturing treatments, a popular application is for altering fluid distribution in wells re-treated without isolation between stages (Pump & Pray/Bullheading) with the intent of increasing the number of re-activated fractures and initiating new fractures through added perforations.
Engineering analysis of the mechanics of fluid diversion has not received the same degree of attention as its use. The reported discussions are often limited in their scope, two-dimensional in structure, and somewhat speculative in their conclusions.
This paper divides the targets of diversion into three categories; at the wellbore/perfs, near wellbore, and deeper inside the fracture. It divides the types of diverters into three categories, mechanical, solid particulate (including proppants), and chemical. The applications are divided into two categories, initial and re-fracturing, together with highlighting their differences and requirements for successful diversion. The paper discusses how presence of proppant changes the fluid distribution in favor of more conductive perforations. It considers the fracture as a three-dimensional structure, extending on both sides of the wellbore. It describes how different diverting agents cause fluid redistribution between the fractures, and the important role of proppant in some applications. It shows that as the target of fluid diversion moves away from the wellbore the chances of its success become smaller and more unpredictable, while also the time before effective diversion takes place becomes longer.
Comprehensive understanding of the mechanics of fluid diversion helps in the selection of the type of diverter and how best to deploy it for achieving specific objectives and results.
In the world of downhole sealing technology, there have been relatively few new developments in recent years. Traditional methods of cement and bridge plugs continue to be the standard but don't always provide an optimal solution. Thankfully there is a new technology on the market that provides a superior seal in wells when compared to traditional methods. That technology is comprised of bismuth and thermite.
Schnitzler, Eduardo (Petrobras) | Ferreira Gonçalez, Luciano (Petrobras) | Savoldi Roman, Roger (Petrobras) | Atanásio Santos da Silva Filho, Djalma (Petrobras) | Marques, Marcello (Petrobras) | Corona Esquassante, Ricardo (Petrobras) | Denadai, Nilson José (Petrobras) | Feliciano da Silva, Manoel (Petrobras) | Rosas Gutterres, Fábio (Petrobras) | Signorini Gozzi, Danilo (Petrobras)
Pre-salt heterogeneous carbonate reservoirs typically present long net pays, high production/injection rates and some flow assurance risks. This paper presents general information, results and lessons learned regarding the installation of Intelligent Well Completion (IWC) in Santos Basin Pre-Salt Cluster (SBPSC) wells. It also presents some important improvements to be introduced in the future IWC systems specification and qualification based on the lessons learnt in these projects, setting some new challenges to the industry.
The benefits expected with the use of IWC are achieved at the expense of challenging well engineering, since well completion design becomes more complex and well construction risks increase. Detailed and integrated planning is essential for the success of the operations, starting at the earliest phases of the well design and continued through detailed execution plans. The use of standardized practices and procedures has led to significant increases on installation performance. On the other hand, an open mind and a constant search for improvements allowed new solutions and procedures to be developed throughout the years. Regarding the system integration, a flexible and standardized control architecture was developed to allow combining different IWC providers and subsea vendors, which proved to be a successful approach.
The most important improvement in IWC installation was the anticipation of the acid stimulation, nowadays performed before the vertical Wet Christmas Tree (WCT) installation. In order to achieve this goal some crucial improvements were gradually implemented in the stimulation practices, such as, an initial injectivity increase solution and some new acid diversion solutions, which allowed eliminating the use of coiled tubing and, as a consequence, the need of a subsea test tree. The well design team conducted an integrated risk assessment to properly evaluate the new practices and establish some actions to reduce the risks. Intense communication between production zones was observed during the acid job in some of the initial wells, ruining the gains of the IWC. After a comprehensive analysis, some possible causes were identified and with the new stimulation practices this issue was eliminated.
Over the years, with the introduction of several improvements, some of them presented in this paper, the well completion duration was reduced to less than 50% of the one observed in the initial wells. This major performance increase has been essential to keep this deepwater projects feasible, especially in the oil scenario seen in recent years. Some of the new practices and lessons learned in this 100 wells equipped with IWC has set groundbreaking practices for Brazilian pre-salt fields development and may stand as a reference for the industry in similar deepwater projects. Additional requirements for future systems are expected to improve even further the performance in this scenario.