The results from acoustic logs can shed light on two issues geologists typically address: erosion and uplift estimation, and organic richness/source-rock potential. The amount of erosion that has occurred in a region that has been uplifted can be estimated from the degree of shale compaction measured by acoustic travel time. This technique assumes that shale compaction is irreversible and that the shale retains the degree of compaction it gained at its maximum burial depth. Acoustic slowness, used alone or in conjunction with formation resistivity, can provide qualitative indications and quantitative determination of source-rock potential (when calibrated to laboratory data). The identification of potential petroleum-source rocks and characterizing the thermal maturity of these rocks is important for assessing petroleum potential (risking) and for basin modeling.
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.
The two basic types of installations are the "fixed"-pump and the "free"-pump design. In the fixed installation, the downhole pump is attached to the end of a tubing string and run into the well. Free-pump installations are designed to allow the downhole pump to be circulated into and out of the well inside the power-fluid string, or it can also be installed and retrieved by wireline operations. Figure 1.2-Free and fixed hydraulic downhole pumping installations. Figure 1.3-Free pump (pump in-and-out operation).
Drilling fluid tests are performed to evaluate the properties and characteristics of the fluid, and to determine its performance limitations. Although drilling-fluid companies might use some tests that are designed for evaluating a proprietary product, the vast majority of field tests are standardized according to American Petroleum Institute Recommended Practices (API RP) 13B-1 and 13B-2, for water-based fluids (WBFs) and oil-based fluids (OBFs), respectively. Table 1 shows typical API-recommended field tests for WBFs. Table 2 shows typical API-recommended field tests for OBFs and synthetic-based fluids (SBFs). Several tests are identical to those performed on WBFs.
The correlation between reduced stage spacing (RSS) and increased well performance is well documented in unconventional plays, as is the propensity for heel-ward bias within the treatment of each stage. The authors postulate that RSS is effective because it results in a more uniform proppant distribution along the length of the lateral, and while it improves well performance, it also increases completion costs.
This study proposes a more effective and cost-neutral way of achieving uniform proppant distribution by using an optimized variable shot cluster (VSC) perforating scheme to ensure all perforations are treated, and to alleviate heel-ward bias. The objective of this study is to design a VSC perforating scheme that provides the same production uplift as RSS, and potentially more uniform fracture half-lengths by preventing uncontrolled half-length growth associated with dominant clusters taking the majority of the treatment.
A downhole camera was utilized on multiple wells to inspect perforations for evidence of erosion and perform a semi-quantitative ranking of the amount of proppant which passed through each perforation. Multiple VSC perforating schemes were observed to help ascertain which variables control the distribution of proppant along the length of a stage.
Results demonstrate that effective flow area (EFA) is the controlling factor that determines which perforations will accept fluid and proppant. In nearly all stages, perforation efficiency is 100% until such a point is reached where beyond that point, perforations do not accept significant volumes of proppant. Limiting the number of perforations to the treatable EFA is required to ensure all perforations in a stage are treated, and an arithmetic model is constructed for the calculation of an appropriate VSC perforating scheme to promote uniform proppant distribution among each cluster.
A cost-effective and tangible method is presented to evaluate uniformity of proppant distribution. Uniform cluster treatment and proppant distribution has the opportunity to replace less direct and costly practices such as RSS, diverters, etc. for improving well production, and has the added benefit of potentially limiting outsized fracture half-length growth associated with dominant clusters. This study was performed in the Marcellus Shale, but generally applies to all unconventional plays where plug-and-perf slickwater hydraulic fracturing treatments are utilized.
The primary objectives of this study are (i) to provide easy-use equations for field engineers to estimate the sand erosion rate of ESP systems, and (ii) to provide recommendations to minimize sand erosion. The overall goal is to minimize the ESP impeller erosion rate to increase its run lifetime; this will directly benefit operators because it implies a reduction in non-productive time due to equipment replacement, service, and workover. The performance of an ESP system under sand production conditions is a crucial issue for operators and service oil companies. Potential and aggressive sand production in oil wells, for example from unconsolidated formations or fractured oil shale, will be an issue for an ESP system even if it was the best economical and technical option among the existing artificial lift systems. Production with solids entrainment significantly affects the reliability of an ESP system and thus results in reduced ESP run lifetime and company revenue.
The approach to accomplish the above study objectives involves analytical formulations and numerical CFD (Computational Fluid Dynamics) simulations. Numerous CFD simulations carried out allowed verifying the validity of the newly developed analytical equation to estimate the solid particle velocity. The methodology follows Finnie's (1960) analytical erosion model, which provides a versatile solution approach to achieve the erosion rate by estimating the kinetic energy of the solid particle and the plastic deformation of the eroded material analytically. The newly developed solid particle velocity equation is a function of liquid density, solid density, impeller radius and angular velocity, blade angles, liquid velocity, solid concentration, and solid impingement angle.
Conclusions from both analytical and numerical studies indicate key results: a) the lower the particle velocity, the lower the erosion rate, b) increasing solids concentration increases erosion rate, and c) increasing solids density decreases the erosion rate. Until now there is no guidance on how to operate an ESP system under liquid-solid flow conditions. The new analytical modeling approach delivers significant reduction of time and effort required to estimate the erosion rate since CFD needs complex pump geometry and mesh construction. A field example shows how to calculate the pump stage erosion rate using the new equation, and to estimate the ESP run life.
Wear of a material by a slurry of liquid and (usually) solids. Geologic - Erosion caused by geologic processes acting over long geologic periods and resulting in the wearing away of mountains and the building up of such landscape features as floodplains and coastal plains. Wear of a material by a slurry of liquid and (usually) solids. Geologic - Erosion caused by geologic processes acting over long geologic periods and resulting in the wearing away of mountains and the building up of such landscape features as floodplains and coastal plains.
The challenge of applying downhole flow control to poorly consolidated, high-permeability, high-productivity, clastic reservoirs is their propensity to produce significant amounts of formation solids. While sand can be a problem for most downhole equipment, it can compromise the ability of intelligent well equipment to do its job. Erosion of choke elements, seal surfaces, control lines, and interference with device movement can render the intelligent completion inoperable, thus losing its functionality and the ability of the operator to use the equipment to realize its long-term value. Sand-control techniques have been applied in these environments with varying degrees of success, and it is safe to say that a properly conceived and executed sand-control strategy can be very effective in reducing or eliminating solid production without unduly restricting productivity. New techniques, such as expandable screens, have been added to tried-and-true techniques such as gravel packs.
This paper presents the first successful application of ceramic sand screens offshore Malaysia. Ceramic sand screens were considered as a remedial sand-control method because of their superior durability and resistance compared with metallic sand screens. Shallow-water offshore production began before 1900 and continues to be important. Technology to maximize economic production from shallow-water fields can be adapted from onshore or deepwater technologies. Standalone-sand-screen (SAS) completion, especially in horizontal gas wells with high potential for sand production, typically suffers from premature failure caused by sand erosion resulting from high velocity in the annulus near the heel section.