Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. Free grains of sand pulled loose by flow, brittle failure, or formation disaggregation and produced with the hydrocarbon production.
Plunger lift is used for recovery, primarily in high gas-oil ratio (GOR) wells, in many countries. Applications include wells with depths of 1,000 to 16,000 ft, producing bottomhole pressures of 50 to 1,500 psia, and liquid rates of 1 to 100 B/D. These are common ranges of application, but not necessarily limits of operation. In fact, plungers have been installed on wells for the sole purpose of preventing paraffin or hydrate buildup, thereby reducing paraffin scraping or methanol injection. For this use, when plunger lift is installed, paraffin, hydrates, and salt should be removed so that the plunger will travel freely up and down the tubing.
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.
Conventional well completions in soft formations (the compressive strength is less than 1,000 psi) commonly produce formation sand or fines with fluids. 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.
Several techniques are available for minimizing sand production from wells. The choices range from simple changes in operating practices to expensive completions, such as sand consolidation or gravel packing. The sand control method selected depends on site-specific conditions, operating practices and economic considerations. This page introduces the available approaches to sand control. Maintenance and workover is a passive approach to sand control. This method basically involves tolerating the sand production and dealing with its effects, if and when necessary. Such an approach requires bailing, washing, and cleaning of surface facilities routinely to maintain well productivity. It can be successful in specific formations and operating environments.
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.
Sand and other solids production can cause problems in PCP systems by accelerating equipment wear, increasing rod torque and power demand, or causing a flow restriction by accumulating around the pump intake, within the pump cavities, or above the pump in the tubing. Also, given its specific gravity of 2.7, even moderate volumes of sand can substantially increase the pressure gradient of the fluid column in the production tubing. Sand production is frequently a byproduct of oil production, especially in some primary heavy oil operations (e.g., Canada) where it is an important part of the recovery process. In such operations, sand influx is usually most severe during the initial stage of production when the volumetric sand cuts can exceed 40%. In high-rate applications (e.g., Venezuela), even low sand cuts can equate to significant volumes of produced sand over time.
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.
KS is a tight-sandstone and high-pressure-high-temperature (HPHT) gas reservoir in northwest China. It is characterized by a depth of more than 6000 m, temperature over 175°C, and pore pressure over 110 MPa. Despite the high unconfined compressive strength (UCS) of sandstone, almost half of the wells encountered sanding issues. The sanding wells exhibited low production rate, nozzle and pipeline erosion, sanding up, and even permanent closure. Investigating the sanding mechanism and developing solutions for sanding prevention are urgent needs due to the economic loss of low production.
An integrated sanding study was conducted to investigate the sanding mechanism. The entire sanding process was analyzed, including stress field alteration during production, rock failure, softening, and sand grain migration. First, wells with sanding issues were identified through production characteristics and field observation. After this, analysis of laboratory tests was performed to better understand the tight-sandstone properties, especially UCS, the softening parameter, and residual strength. Based on the tests, an elastoplastic damage model was proposed to delineate rock failure and sanding behavior. Then, a finite element model was built to simulate the damage of a perforation hole with field data, including hole diameter and length, rock stiffness and strength, drawdown, depletion, and so on. More simulation scenarios were performed to investigate the continuous sanding, transient sanding, and water hammer effect. Grain migration in perforation holes and in pipelines was also studied.
It was revealed that shear failure of perforation hole induced by drawdown and depletion was the root cause of sanding problem. Meanwhile, it was also confirmed that erosion and water hammer effect had very limited effect on sanding. Use of the elastoplastic damage model for the simulation of perforation hole failure enabled predicting the sand amount and determining the critical drawdown and depletion for sanding. In the end, an approach to identifying wells with high sanding risk and the key factors behind the sanding were provided, and sanding prevention suggestions were proposed.
The new elastoplastic damage model explains the sanding mechanism in a tight-sandstone reservoir and enables evaluating the sand volume, which has rarely been published previously. Laboratory tests, field observation, and numerical simulation were combined effectively to investigate the sanding issue. By utilizing the model, producers can find the key factors behind sanding issues, prevent sanding with a better production strategy, and avoid the economic loss, which are critical for the long-term exploration and production of this area.
This paper proposes a new work flow to simulate water-hammer events, the resulting wellbore failure, and sand production in water injectors. Many column inches are filled with discussion of how companies need to operate in the lower-for-longer market that the upstream oil and gas industry continues to face.