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The term "resin," as used in this page, refers to an organic, polymer-based, solid plastic material. Resins do not contain a significant amount of a solvent phase (as do gels), and resins are placed downhole in a liquid monomeric (or oligomeric) state and polymerized in situ to the mature solid state. Oilfield resins are exceptionally strong materials for use in blocking and plugging fluid flow in the wellbore and/or the very near-wellbore region. The three classical oilfield resins discussed here have exceptionally good compressive strengths. Also, these three resins usually have good bonding strength to oil-free rock surfaces.
Propping agents are required to "prop open" the fracture once the pumps are shut down and the fracture begins to close. The ideal propping agent is strong, resistant to crushing, resistant to corrosion, has a low density, and is readily available at low cost. The products that best meet these desired traits are silica sand, resin-coated sand (RCS), and ceramic proppants. Silica sand is obtamust be tested to be sure it has the necessary compressive strength to be used in any specific situation. Generally, sand is used to prop open fractures in shallow formations.
An understanding of rock strength is important for designing recovery plans for a reservoir and for developing an appropriate reservoir simulation. A detailed discussion of rock failure can be found in Rock failure relationships and Compressive strength of rocks. But the data needed for these methods may not be readily available, so there is a desire to use data available from well logs that are available. Several techniques have been proposed for deriving rock strength from well log parameters. Coates and Denoo calculated stresses induced around a borehole and estimated failure from assumed linear envelopes with strength parameters derived from shear and compressional velocities.
This page provides an introduction to stress-strain relationships. They form the foundation for several rock properties such as elastic moduli (incompressibility), effective media theory, elastic wave velocity, and rock strength. Stress is the force per unit area. The metric units of stress or pressure are N/m2 or Pascals (Pa). Other units that are commonly used are bars, megapascals (MPa), and lbm/in.2
The primary fluids encountered are brines and hydrocarbon oils and gases. Drilling, completion, and fracturing fluids can also be present, and their effects are typically studied to prevent formation damage. This page will concentrate on the role of water and, in particular, how water saturation can influence rock strengths measured in the laboratory or derived from well logs. Pore fluid pressures will reduce the effective stress supported by the rock mineral frame. This effect has been well known since the publication of Terzaghi and Peck and has been documented by numerous investigators.
Understanding rock failure relationships is important because under reservoir pressure and stress conditions, production can induce rock failure, sometime with catastrophic effects. By applying strength criteria, within reservoir simulators we can predict when problems might occur. Stress strain relationships in rocks examined the elastic behavior of rocks, which was largely reversible. Here we deal with permanent deformation. By rock failure, we mean the formation of faults and fracture planes, crushing, and relative motion of individual mineral grains and cements.
Pingo, Abraham (Graña Montero Petrolera S.A) | Vera, Christian (Graña Montero Petrolera S.A) | Soriano, Victor Hugo (Graña Montero Petrolera S.A) | Villanueva, Jaime (Consultor Independiente) | Ahmed, Ramadan (University of Oklahoma) | Hilario Poma, Juan (Halliburton) | Paredes, José Luis (Halliburton)
The Talara Basin in Perú is a mature oil field where production is extremely marginal, and well-construction designs are tailored to this condition to optimize well costs. However, one well recently drilled in this area was identified with the original reservoir pressure, and the well design was not based on this pressure. As a result, drilling issues such as fluid loss and lost circulation were carefully monitored while trying to control reservoir pressure in a long open-hole section. The challenges faced while cementing a high-pressure zone with controlled fluid losses and achieving well objectives in terms of safety, reliability, and lifetime zonal isolation of the well are discussed.
At the planning stage, a mud density of 13 lbm/gal was considered adequate to control downhole pressure (overbalanced); however, before reaching total depth, signs of high pressure were observed while drilling through a low-permeability formation. Mud density was significantly increased to control the well while monitoring the fluid return. When the mud weight reached 15.5 lbm/gal, losses were reported. Finally, the well was stabilized at 15.8 lbm/gal using different lost circulation pills. This event complicated the cementing operation because it substantially increased the necessary slurry density (16.1-lbm/gal lead and 17-lbm/gal tail). Nevertheless, proper cementing design and effective slurry placement using conventional techniques resulted in successful cementing operation with full cement return to the surface.
High-density cement slurries were successfully mixed and pumped regardless of their highly viscous property. The cementing unit and personnel were able to manage this vital operation without facing major problems. Before bumping the plug, circulating pressure was close to the theoretical value, confirming that the cement slurry column was as per the design without noticeable losses into the formation. Full cement returns confirmed a successful cement placement. Final circulating pressure was 2,370 psi, and it increased to 2,900 psi when the plug was bumped. The cement evaluation log obtained after 24 hours indicated good bonding, effective mud displacement, and a successful cement operation. The well was then fractured and put on production. Neither corrective work nor a well-integrity remediation operation was necessary.
Drilling the abnormally pressurized well was extremely challenging because of unexpected high pressure and associated problems, including working with high-density slurries and using various fluid additives to achieve adequate zonal isolation for future stimulation works. Techniques involved and experiences gained while undertaking this considerably challenging project are discussed in this article.
In 2019, a well operator in North Sea UK executed a conductor batch drilling and cementing campaign consisting of eight 28-in conductor casings. With the aim to further optimize the cementing operation efficiency and reduce wait-on-cement (WOC) time, thus helping the operator to reduce drilling time to complete this batch drilling campaign, the cementing service company used an integrated approach with the application of dual-component cement blend with high compressive strength development and inner string stabbed-in cementing technique in this conductor batch cementing campaign.
The common cementing objective for conductor casing is to provide structural support for the wellhead by having the top of cement in the annulus at the seabed, depending on the well fatigue limit analysis result. With the weak unconsolidated formation at shallow depth and the low seabed temperature, the challenge was to provide an engineered cementing solution with high early compressive strength development rate at low temperature and of lighter density to avoid fracturing the weak formation. The cementing service company formulated a dual component cement blend to provide such a cement slurry by combining the rapid hardening cement and hollow silicate spheres. To further optimize the drilling operation efficiency from cementing perspective, an inner string stabbed-in cementing technique with double float casing shoe was used to eliminate the time to drill out cement left inside the casing shoe track.
The 36-in. open hole section was drilled to 310 m, and 28-in. conductor casing was cemented with a lightweight rapid hardening cement slurry. The cement slurry density was formulated at 1.5-SG with seawater as the base fluid to further accelerate the setting time and compressive strength development of the cement. This paper discusses the risk assessment and safety factors that were considered in the cement job design phase, including the laboratory testing that was carried out according to
The conductor casing batch cementing job successfully met the well timing objective set by the well operator. An estimated 96 hours was saved from the conductor batching campaign with this integrated approach to optimize operational efficiency from cementing perspective. This paper will help to establish a solid case history for well operators to further improve the drilling operational efficiency for conductor drilling.
Malaieri, Mohammadreza (Schulich School of Engineering, University of Calgary) | Matoorian, Raya (Schulich School of Engineering, University of Calgary) | Aguilera, Roberto (Schulich School of Engineering, University of Calgary)
A Pickett plot is a powerful graphical technique for petrophysical analysis of well logs, which was developed initially to represent Archie's equation visually. Pickett plots rely on pattern recognition on a log-log scale observable on a set of porosities and the corresponding true resistivities taken from well logs. The analyses of these plots have been used in the past, primarily for the determination of water saturation. However, throughout the past years, Pickett plots have been extended and modified for the evaluation of other reservoir parameters of interest, such as permeability, process/delivery speed, bulk volume water, and pore throat apertures.
In some recent works, applications of the Pickett plot have been extended from representing only a snapshot on time to describing and explaining several millions of years of burial, compaction, maturation trajectories, and petroleum generation. The word ‘petroleum’ as used in this paper includes oil, gas, and natural gas liquids.
In this study, the Pickett plot has been modified and extended to include geomechanical parameters such as
Mechanical properties are usually measured in laboratory experiments such as Triaxial Compression Tests carried out on core samples. But cores are not always available for testing; therefore, the original contribution of this paper is the construction of a modified Pickett plot that can help to perform quick and reasonable evaluations of geomechanical properties while at the same time carrying out standard petrophysical analysis of petroleum reservoirs. This type of integrated petrophysical-geomechanical interpretation on a single plot is not currently available in the literature.