Mechanical failure in rocks generally means either fracturing or permanent deformation as a result of compression. While many methods for calculating failure relationships exist, an initial measure of the compressive strength of reservoir rocks is still needed for use in those calculations. General rock failure criterion can be reduced to a few parameters dependent on lithology (m) and the uniaxial compressive strength (C0). Lithology is commonly derived during log analysis, so m may be estimated (Table 1). What is needed still is an initial measure of rock strength provided by C0.
These formations are usually geologically young (Tertiary age) and shallow, and they have little or no natural cementation. Sand production is unwanted because it can plug wells, erode equipment, and reduce well productivity. It also has no economic value. Nonetheless, formation sand production from wells is dealt with daily on a global basis. In certain producing regions, sand control completions are the dominant type and result in considerable added expense to operations.
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.
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.
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. By rock failure, we mean the formation of faults and fracture planes, crushing, and relative motion of individual mineral grains and cements. The latter deformation is caused by a broad distribution of fracture zones or general grain crushing during compaction. We will not consider deformation caused by plastic strains of the mineral components, as is common in salt and in calcite at higher temperatures.
Rollins, Brandon (Whiting Petroleum Corporation) | Lauer, Travis (Whiting Petroleum Corporation) | Jordan, Andrew (BJ Services) | Albrighton, Lucas (BJ Services) | Spirek, Matthew (BJ Services) | Pernites, Roderick (BJ Services)
Frequently exposed weak formations require the use of lighter slurries, and with increased wellbore pressures encountered during fracture stimulations, stronger cements are essential. Lighter, stronger cementing technologies are the key to ensuring well integrity and enabling simple, cost-effective well construction designs.
This paper describes the benefits and features of newly developed, lightweight cementing materials available for operations in the Williston Basin. Applications of these materials are supported by case histories and extensive laboratory test data.
Regionally, materials have been identified that can be used to produce innovative, bulk lightweight cementing systems. These materials can be inter-ground with the cement during manufacturing or blended with bulk cement. Both methods create cost-effective, high-strength cement systems that can easily be formulated into slurries with densities as low as 10.5 ppg.
Comprehensive laboratory test data was generated to support well simulations and field trials of the new materials. Field trial data is then analyzed to illustrate the benefits of cement systems.
Economical lightweight cements are commonly produced with fly ash extended systems, however, these systems have low strength at low densities. Lightweight, high-strength, fit-for-purpose cement materials are common in southern oil and gas basins, but transporting these materials to northern states is cost prohibitive. Exotic solutions to create lightweight cements (nitrogen foams or hollow glass micro-beads) are available but expensive, adding considerable operational complexity.
Laboratory data demonstrates mechanical properties of the cement systems, slurry properties and set characteristics. The new, low-density cement systems show far greater compressive strengths than conventional blends. Conventional slurry provides a compressive strength of 500 psi, whereas the new low-density 12 ppg blends provide compressive strengths greater than 1,000 psi.
Additional practical benefits of these systems are illustrated by varying water content to improve slurry density from 11 to 13.5 ppg without additional cementing additives.
Multiple case histories illustrate the results of the applications of these materials at downhole temperatures ranging from 140°F to 220°F and well depths up to 11,000 ft TVD in the Dakota, Mowry and Charles Salt formations.
The limitations associated with traditional cementing materials will no longer restrict the creation of efficient well designs in northern states with the implementation of new, low-density cement systems necessary to exploit these oil and gas basins. Using lighter, stronger cement technologies will provide simple, cost-effective designs that are needed to ensure wellbore integrity in the Williston Basin.
Resin coated proppant is used in hydraulic fracturing applications to stimulate oil/gas wells for production enhancement. The objective of this study was to perform a rock mechanical study to evaluate long term stability of RCP combined with various additives currently being used in screenless propped hydraulic fracturing completions in the sandstone formations to provide a tool for the industry to know exactly the duration of the shut-in time before putting well back in production. A new experimental method was developed to monitor the curing process of resin-coated proppant as temperature increases. The velocity of both shear and compressional waves were being monitored as a function of temperature. The tested resin of coated proppant sample has been housed in a pressurized vessel. The pressurized vessel was subjected to varying temperature profiles to mimic the recovery of reservoir temperature following propped hydraulic fracturing treatment. The placed proppant should attain an optimum consolidation to minimize proppant flow back.
Historically, sand production from poorly consolidated and unconsolidated sand formation, is a serious problem. These problems can lead to lost reservoir productivity, increased rates of required workover expenditure, fines plugging gravel packs, screens, perforations, tubulars and surface flow lines or separators. These problems hamper hydrocarbon production.
Predicting whether a well will produce fluids without producing sand has been the goal of many completion engineers and research projects. There are a number of analytical techniques and guidelines to assist in determining if sand control is necessary, but no technique has proven to be universally acceptable or completely accurate. In some geographic regions, guidelines and rules of thumb apply that have little validity in other areas of the world. Predicting whether a formation will or will not produce sand is not an exact science, and more refinement is needed. Until better prediction techniques are available, the best way of determining the need for sand control in a particular well is to perform an extended production test with a conventional completion and observe whether sand production occurs.
Bagheri, Mohammadreza (Research Centre for Fluid and Complex Systems, Coventry University) | Shariatipour, Seyed M. (Research Centre for Fluid and Complex Systems, Coventry University) | Ganjian, Eshmaiel (School of Energy, Construction and Environment, Built & Natural Environment Research Centre, Coventry University)
The fluid pressure, the stress due to the column of the cement in the annulus of oil and gas wells, and the radial pressure exerted on the cement sheath from the surrounding geological layers all affect the integrity of the cement sheath. This paper studies the impact of CO2-bearing fluids, coupled with the geomechanical alterations within the cement matrix on its integrity. These geochemical and geomechanical alterations within the cement matrix have been coupled to determine the cement lifespan. Two main scenarios including radial cracking and radial compaction, were assumed in order to investigate the behaviour of the cement matrix exposed to CO2-bearing fluids over long periods. If the radial pressure from the surrounding rocks on the cement matrix overcomes the strength of the degraded layers within the cement matrix, cement failure can be postponed, while on the other hand, high vertical stress on the cement matrix in the absence of a proper radial pressure can lead to a reduction in the cement lifespan. The radial cracking process generates local areas of high permeability around the outer face of the cement sheath. Our simulation results show at the shallower depths the cement matrices resist CO2-bearing fluids more and this delays exponentially the travel time of CO2-bearing fluids towards the Earth's surface. This is based on the evolution of CO2 gas from the aqueous phase due to the reduction in the fluid pressure at shallower depths, and consumption of CO2 in the reactions which occur at the deeper locations.