Bullet gun, abrasive, water jets, and shaped charges are perforating methods used to initiate a hole from the wellbore through the casing and any cement sheath into the producing zone. Bullet speed exiting the barrel is usually approximately 900 m/s (3000 ft/sec). Penetration in higher strength casing alloy pipe and harder formations is more difficult in most cases and not feasible in others. When successful, the bullet creates a very round entrance hole but may often create a hole with sharp internal burrs. Figure 1 shows a bullet-perforated casing from a surface test.
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.
Prepacking can be defined as any method that intentionally places gravel into the perforation tunnels. Filling of perforation tunnels can be accomplished either with a dedicated operation before performing the gravel pack or simultaneously with it. The technique used is normally dictated by well parameters. Gravel packing cased-hole completions in vertical and deviated wells are more common than openhole completions, particularly in shaley reservoirs. However, cased-hole gravel packs have an important requirement that is easily overlooked.
Formation damage caused by drilling-fluid invasion, production, or injection can lead to positive skin factors and affect fluid flow by reducing permeability. When mud filtrate invades the formation surrounding a borehole, it will generally remain in the formation even after the well is cased and perforated. This mud filtrate in the formation reduces the effective permeability to hydrocarbons near the wellbore. It may also cause clays in the formation to swell, reducing the absolute permeability of the formation. In addition, solid particles from the mud may enter the formation and reduce permeability at the formation face.
When cement is bullheaded into the annulus to displace mud, the differential pressure between the cement and the formation fluid can lead to a significant loss of cement filtrate into the formation. If, however, large volumes of cement filtrate invade the rock, the possibility of formation damage exists. As the cement filtrate invades the formation and reacts with the formation minerals, its pH is reduced from 12 to a pH buffered by the formation minerals. This rapid change in pH can result in the formation of inorganic precipitates such calcium carbonate and calcium sulfate. Evidence of formation damage induced by cement filtrates has been clearly demonstrated in experimental studies presented in Cunningham and Smithand Jones, et al..
Considering the important role that perforation laboratory testing can play in establishing field completion strategies, and thus ultimately well performance, efforts are currently underway to further strengthen the link between laboratory results and field well performance predictions. Some of these efforts focus on integrating advanced diagnostic and computational tools (namely computed tomography (CT), and pore-scale flow simulation) into the perforation testing workflow. This integration enables local variations in permeability and porosity to be identified and quantified, thus improving the interpretation of perforation laboratory results, and ultimately the translation of these results to the downhole environment.
CT techniques have been used for core analysis, characterization, and flow visualization since the early 1980s. By the early 1990s, these techniques were being applied to the investigation of laboratory-perforated cores to enhance the interpretation of tests conducted following API RP19B Section 2 or 4. This application has increased dramatically since 2012, following the installation of a CT scanning system on-site at a perforating laboratory facility. As a result, this non-destructive technique has become a preferred method to routinely characterize perforation tunnels and the surrounding rock, as well as to enable the repeated inspection of a perforated core at multiple steps throughout a test sequence designed to mimic field operations scenarios. Coinciding with this development has been the advancement and application of micro-CT technology to better understand pore-scale phenomena, both near and away from the perforation.
This paper introduces an integrated test program currently underway and summarizes key results from two experiments in which stressed rock targets were perforated under significantly different conditions. The first experiment involved perforating a moderate strength sandstone core under conditions that retained substantially all perforation damage, thus preserving the "crushed zone". Micro-CT analysis of different locations within the crushed zone region revealed significant compaction, with porosity reductions ranging from 10 to 50% below that of the native rock. Permeability at one of these selected locations was determined and found to be reduced by approximately 35% below the native rock value. The second experiment involved perforating a very high-strength sandstone core under conditions intended to produce full cleanup. CT and micro-CT analysis revealed fine fractures near the tunnel tip and confirmed the near-complete removal of the perforation damage, with only a very thin (less than 1 mm) compacted zone remaining at the tunnel wall. Although this region is interpreted to have very low permeability (as indicated by the near-zero connected porosity detectable at the resolution investigated), a fracture network combined with the shell’s minimal thickness suggests that this would provide a minimal impediment to inflow.
Ongoing work aims to expand these findings and capabilities. A main effort going forward centers on simulating core-scale perforation inflow, incorporating the localized rock property variations determined as described in this paper. Additional property variations away from the perforation (for example, natural heterogeneity and/or anisotropy that often exist in reservoir wellcore samples) will also be taken into account. Such localized variations, both near and away from the perforation, are generally not taken into account in typical Section 4 test programs. Consequently, this ongoing effort will ultimately strengthen the relevance of Section 4 results to the downhole environment.
This paper investigates the effects of high production rates on well performance for a casedhole gas well using two types of completion schemes: frac pack and gravel pack. We model fluid dynamics in the near-wellbore region, where the most dramatic changes in pressure and velocity are expected to occur, using computational fluid dynamics (CFD). The fluid-flow model is dependent on the Navier-Stokes equations augmented with the Forchheimer equation to study inertial and turbulence effects in regions where the velocity increases and decreases sharply over a relatively small length scale. Real-gas properties are incorporated into the momentum-balance equation using the Soave-Redlich-Kwong (SRK) equation of state (EOS) (SRK-EOS). The near-wellbore model is pressure-driven under steady-state and isothermal conditions. Well-performance curves are generated depending on simulation results for both completion schemes. Furthermore, we introduce the concept of rate-dependent pseudoskin factor to assess inertial and turbulence kinetic energy (TKE) losses under various pressure differential. Analysis of the simulation results suggests that the rate-dependent pseudoskin changes from negative at low gas-production rates to positive at medium-to-high gas-production rates. This is primarily because of the inertial and turbulence effects being triggered at a certain flow rate, which we define as the optimal operating point. We demonstrate that the gas-deliverability curve plotted along with the pseudoskin-factor curve allows us to estimate the optimal operating condition as the point where the rate-dependent pseudoskin is zero. An analytical model to estimate the optimal production rate is proposed as an extension to typical multirate tests.
In recent years, numerical tools increasingly have been used in conjunction with experiments to provide better insight into the flow characteristics of perforated cores and perforated well-scale formations. Several numerical studies on perforation fluid flow have been conducted for core scale. However, comprehensive details relating to the modeling of perforation-zone damage and thickness, flow directionality, debris mechanisms, and implications for cleanup have not been studied in detail. In addition, most computational fluid dynamics (CFD) studies have used traditional Navier-Stokes-based solvers. In this study, the authors have used a commercially available flow-simulation software based on the lattice Boltzmann method (LBM) to calculate the complex flow and cleanup mechanisms around the perforation tunnel.
Although clustered perforations have become a primary choice of completion for horizontal wells in the development of low-permeability reservoirs, downhole measurements and production logging often indicate nonuniform production from the perforation clusters, with some of them not stimulated or not contributing to the production. One of the mechanisms contributing to this is nonuniform/inefficient breakdown of the perforations. However, being able to assess the effectiveness of perforation breakdown because of lateral variation of the formation properties and stresses is challenging, not only because of the lack of the data, but also because of the lack of a practical engineering model to predict the fracture initiation and breakdown pressures for cased and perforated completions due to the complexity of well configuration and perforation geometry. In this paper, an analytical fracture initiation model is presented along with the comparison against 3D numerical simulations and published experimental data. The breakdown pressure data from a Marcellus shale horizontal test well in the US Department of Energy (DOE)–sponsored Marcellus Shale Energy and Environmental Laboratory consortium are analyzed and compared to the model prediction using the high-resolution 1D mechanical earth model derived from high-tier logs.
Yang, Xiangtong (PetroChina) | Qiu, Kaibin (Schlumberger) | Zhang, Yang (PetroChina) | Huang, Yongjie (Schlumberger) | Fan, Wentong (PetroChina) | Pan, Yuanwei (Schlumberger) | Xu, Guowei (PetroChina) | Xian, ChengGang (Schlumberger)
Keshen is a high-pressure/high-temperature (HP/HT) tight-sandstone gas reservoir with reservoir pressure greater than 110 MPa and temperature more than 175°C. The sandstone is hard, with unconfined compressive strength (UCS) greater than 100 MPa. Given the HP/HT nature and natural-fracture systems in the reservoir, with aid of stimulation, many wells produced at a high rate, with the mean value exceeding 500 000 m3/d. In the last few years, many production wells in this reservoir experienced severe sanding issues that contradicted the conventional understanding that sanding would not occur in such hard rock. The sanding wells exhibited large fluctuations of production rate and wellhead pressure, erosion of chokes and nozzles, and eventually major or even complete loss of production. A solution to address the sanding issues was urgently needed because they had caused a major decline in production and resulted in significant economic loss.
Because of the unconventional nature of the sanding issues, the typical sanding-prediction methods dependent on evaluating rock failure were not adequate to reveal the underlying sanding mechanism and develop a viable operational solution. To this end, a new work flow was formulated and applied to this study. The work flow started with detailed data mining on the large amount of drilling, completion, stimulation, and production data of more than 51 wells from this reservoir to investigate possible relationships of drilling practices, completion options, and production schedules to the occurrence and severity of sanding issues. The analysis revealed that downhole flow velocity and production drawdown were the two major controlling factors in the occurrence of sand production. Further geomechanics simulation and particle-migration simulation with a multiphase dynamic flow simulator confirmed that the production drawdown would cause failure of the rock near the wellbore and the gas flow could transport the sand debris to the wellbore and lift it up to the surface. In addition, the fluctuation of production rate was caused by blockage because of the accumulation of sand particles in the wells and production tubing that were flushed out after downhole-pressure buildup.
Using the analysis, the threshold of flow velocity and the threshold of drawdown were identified, and these thresholds can be used in the reservoir management to effectively address the sanding issues.
The experience in Keshen shows that sanding is possible in HP/HT high-productivity sandstone gas reservoirs, even in an extremely hard formation, which overturns some prior conceptions on sanding. The information shared from this paper could attract the attention of those operating similar HP/HT tight-sandstone reservoirs around the world.