The redistribution of stresses around a fractured vertical well has two sources: opening of propped fracture (mechanical effects) and production or injection of fluids in the reservoir (poroelastic effects). In this paper, the coupling of both phenomena was numerically modeled to quantify the extent of stress reorientation around fractured production wells. The results have been compared to field data from the Codell tight gas formation and analyzed for their impact on refracturing operations.
For previously fractured wells, a secondary fracture may be initiated perpendicular to the first fracture if a stress-reversal region is present. Altered-stress refracturing makes it possible to access zones of the reservoirs that are less depleted, thus increasing well production and reserves.
The results of our model quantitatively agree with previous tiltmeter measurements, confirming the existence of refracture reorientation in the Codell formation. The performance of refracturing treatments has been observed to be highly variable in the Wattenberg field (Colorado), with some wells underperforming while others are restored to initial production rates. Historical production from neighboring wells and initial fracture performance were shown to impact the potential benefits from refracturing predicted by the numerical model.
This paper introduces a 3D model, coupling mechanical and poroelastic stress reorientation used to interpret tiltmeter measurements and historical production in the Codell tight gas formation. Guidelines are drawn from the Wattenberg field case study that allow an operator to select candidate wells, choose the timing of the refracture operation in the life of the well, and evaluate the potential increase in well production after refracturing.
A new family of water-based drilling fluids that contain nano-particles has been tested to evaluate its interaction with shales. It was shown in an earlier paper that nano-particles dramatically reduce the flow of water into a shale formation. In this study we have developed and tested a new family of commercially available drilling fluids that can be used to drill shales.
Drilling shale formations with water-based fluids offers some tremendous environmental and economic advantages. To date the use of such fluids have been limited to hard shales such as the Barnett. In this paper we have developed and lab tested water-based drilling fluids that contain nano-particles that can be applied to a much broader range of shales.
Water-based drilling fluids have been formulated that incorporate nano-particles in them at a very reasonable cost. The rheology and stability of these muds were tested. A family of such fluids has been developed and tested in the lab. It is found that the muds are quite stable at elevated pressures and temperatures and offer a wide range of rheological properties. These muds also offer good lubricity and are, therefore suitable for applications in drilling the lateral section of the hole in shales. Tests were also conducted to measure the extent of invasion of water into shales when they are exposed to nano-particle based drilling fluids. The invasion into the shale was reduced by 10 to 100 times indicating that wellbore instability problems will be minimized when these muds are used.
Drilling long lateral sections in shales and tight gas reservoirs is often the largest capital cost associated with the development of these resources. Nano-particle based drilling fluids have the potential to significantly cut these drilling and disposal costs and offer significant environmental benefits.
Chanpura, Rajesh A. (Schlumberger) | Mondal, Somnath (University of Texas At Austin) | Sharma, Mukul M. (The University of Texas At Austin) | Andrews, Jamie Stuart (Statoil ASA) | Mathisen, Anne Mette (Statoil ASA) | Martin, Frederic (Shtokman Development AG) | Marpaung, Fivman (Total) | Ayoub, Joseph Adib (Schlumberger) | Parlar, Mehmet (Schlumberger)
Many completion engineers use laboratory sand-retention testing as a tool to select a screen for standalone sand-control applications, some focusing on prepack and others on slurry testing. Those who use slurry tests for screen selection typically do so based on the conventional wisdom that slurry testing is more challenging; thus, it represents the worst-case scenario for sand production. Furthermore, the general belief in the industry has been that metal-mesh screens with a "pore structure?? are
better for sand retention compared with wire-wrap screens (WWS) of slot geometry, although they are more prone to "plugging.?? These are just a few of the many myths that exist in screen selection for standalone screen (SAS) applications. Recent papers on modeling of sand retention by screens of various geometries, and supported by laboratory experiments, provided the tools for predicting sand production in both prepack and slurry conditions, as well as allowing for a systematic performance comparison of various screens using the entire particle-size distribution (PSD) of formation sands (Chanpura, Fidan et al. 2011; Chanpura, Mondal et al. 2012; Mondal, Sharma, Chanpura et al. 2011; Mondal, Sharma, Hodge et al. 2011).
In this paper, we discuss and challenge many myths in screen selection for SAS applications and substantiate our findings with modeling and experimental data. The conditions under which a slurry or a prepack test would be more conservative are identified, highlighting the mechanisms of sand retention (size exclusion or bridging dominated). We demonstrate the current thinking that prepack tests are always more conservative from a sand production standpoint is incorrect. We also show that the concept that metal-mesh screens are always superior for sand retention than WWS is incorrect, highlighting the factors that affect sand production through various screens (open flow area (OFA), wire thickness, fraction of bridging-size particles in the formation sand etc.). Finally, a methodology for screen selection in SAS applications is proposed.
While several three-dimensional (3D) fracturing models exist for incompressible water-based fluids, none are able to capture the thermal and compositional effects that are important when using energized fluids. This paper introduces a new 3D, compositional, non-isothermal, fracturing model designed for compressible fracturing fluids. The new model predicts changes in temperature and fluid density. These changes are treated on a firm theoretical basis by using an energy balance equation and an equation of state, both in the fracture and in the wellbore. The model is capable of handling any multi-component mixture of fluids and chemicals. Changes in phase behavior with temperature, pressure, and composition can be modeled.
A new simulator has been developed based on the compositional model presented in this paper. The simulator is validated for traditional fluid formulations against known analytical solutions and against a well-established commercial fracturing simulator. Results from the new simulator are then presented for energized fluids such as CO2 and LPG. This tool is specifically suited for fracture design in formations in which energized fluids constitute a viable alternative to traditional fracturing fluids. This is notably the case in reservoirs that are depleted, under-saturated, or water-sensitive.
Limitations of Conventional Water Fracture Treatments
In many unconventional reservoirs, gas wells do not perform up to potential following water-based fracturing treatments. The sub-optimal fracture productivity can be a result of a combination of factors: (1) low reservoir pressure, (2) limited fracture length, (3) poor proppant placement, and (4) low proppant conductivity. Numerous mechanisms have been identified as detrimental to fracture conductivity: (1) water blocking, (2) gel damage, (3) proppant settling, (4) proppant embedment, (5) fines plugging, and (6) clay swelling.
In many tight gas and shale gas formations, water is the wetting phase and the initial water saturation is very low. The invasion (imbibition) of water from the fracturing fluid can be very detrimental to gas productivity as any additional water remains trapped because of capillary retention. The pressure drawdown required to recover water can be very high in tight formations (Mahadevan and Sharma 2005). As seen in Fig. 1, the increase in water saturation significantly reduces the relative permeability of gas, sometimes by orders of magnitude. This adverse phenomenon, referred to as water blocking (or trapping), is observed in many reservoirs (Al-Anazi et al. 2002; Mahadevan et al. 2007; Parekh et al. 2004; Gupta 2011).
Fines generation and clay swelling in water-sensitive formations can also reduce gas productivity. Clays expand as water invades the formation and contacts the clays around the fracture. The resulting decrease in rock permeability reduces the ability of the gas to flow from the reservoir to the fracture. Additionally, the transport of gas can be impaired inside the fracture. In many shales and clay-rich sands, proppant conductivity drops considerably in the presence of water. The rock-to-fluid interactions soften the rock, further promoting proppant embedment as the rock closes on the proppant. In such cases, it is critical to reduce the amount of water invading the formation.
Mondal, Somnath (University of Texas at Austin) | Sharma, Mukul M. (University of Texas at Austin) | Hodge, Richard M. (ConocoPhillips) | Chanpura, Rajesh A. (Schlumberger) | Parlar, Mehmet (Schlumberger) | Ayoub, Joseph A. (Schlumberger)
Woven-metal-mesh sand screens, commonly known as premium screens, have been used extensively by the industry. Sand-retention testing is often executed to evaluate the performance of these screens and to establish empirical guidelines for screen-size selection. These tests are tedious, however, and the results are prone to artifacts and have been used, at best, to correlate trends in sand-retention performance with select sand-size-distribution parameters. A new method incorporating results from numerical modeling, in addition to experimental data, is presented to estimate the mass and size distribution of the produced solids in prepack sand-retention tests (SRTs) through premium screens. This method provides a fast, reliable correlation to estimate sand production through premium mesh screens when the size distribution of the formation sand is known.
This paper presents results from a wide range of pre-pack sand-retention experiments. In these tests, which represent complete hole collapse, the mass of sand produced and its size distribution over time are measured. Results of 3D, discrete-element computer simulations of woven-screen geometry placed in contact with granular sandpacks of approximately 100,000 particles are also presented. On the basis of both the simulations and the experiments, a new method for screen selection is presented. This method is based on a correlation that allows one to use the entire sand-size distribution of the formation sand and to estimate the mass and size distribution of the produced sand. The method is validated by comparisons with experimental data.
A new method and new correlations for estimating the mass and size distribution of produced solids in prepack tests through premium screens are presented. Key differences in sand-retention mechanisms between premium screens and wire-wrapped screens (WWSs) have been identified. The method uses the entire-formation sand-size distribution (as opposed to a single design point), and has been validated with laboratory tests. The method also helps in screening anomalous test results.
With the growing interest in low-permeability gas plays, foam fracturing fluids are now well established as a viable alternative to traditional fracturing fluids. Present practices in energized fracturing treatments remain, nonetheless, rudimentary in comparison to other fracturing-fluid technologies because of our limited understanding of multiphase fluid-loss and phase behavior occurring in these complex fluids. This paper assesses the fluid-loss benefits introduced by energizing the fracturing fluid.
A new laboratory apparatus has been specifically designed and built for measuring the leakoff rates for both gas and liquid phases under dynamic fluid-loss conditions. This paper provides experimental leakoff results for linear guar gels and for N2/guar foam-based fracturing fluids under a wide range of fracturing conditions. In particular, the effects of the rock permeability, the foam quality, and the pressure drop are investigated. Analysis of dynamic leakoff data provides an understanding of the complex mechanisms of viscous invasion and filter-cake formation occurring at the pore scale.
This study presents data supporting the superior fluid-loss behavior of foams, which exhibit minor liquid invasion and limited damage. It also shows direct measurements of the ability of the gas component to leakoff into the invaded zone, thereby increasing the gas saturation around the fracture and enhancing the gas productivity during flowback. Our conclusions not only confirm but add to the findings of McGowen and Vitthal (1996a, b) for linear gels and the findings of Harris (1985) for nitrogen foams.
Fluid penetration from water-based muds into shale formations results in swelling and subsequent wellbore instability. Particles in conventional drilling fluids are too large to seal the nano-sized pore throats of shales and to build an effective mudcake on the shale surface and reduce fluid invasion. This paper presents laboratory data showing the positive effect of adding commercially available, inexpensive, nonmodified silica nanoparticles (NP) (particle sizes vary from 5 to 22 nm) to water-based drilling muds and their effect on water invasion into shale.
Six brands of commercial and nonmodified nanoparticles were tested and screened by running a three-step pressure penetration (PP) test (brine, base mud, nanoparticle mud). Two types of common water-based muds, a bentonite mud and a low-solids mud (LSM), in contact with Atoka shale were studied with and without the addition of 10 wt% nanoparticles. We found that a large reduction in shale permeability was observed when using the muds to which the nonmodified nanoparticles had been added. For the bentonite muds, the permeability of Atoka shale decreased by 57.72 to 99.33%, and, for the LSMs, the permeability of Atoka shale decreased by 45.67 to 87.63%. Higher plastic viscosity (PV) and lower yield point (YP) and fluid loss (FL) of the nanoparticle muds compared with base muds were also observed. We also found that nanoparticles varying in size from 7 to 15 nm and a concentration of 10 wt% are shown to be effective at reducing shale permeability, thereby reducing the interaction between Atoka shale and a water-based drilling fluid.
This study shows for the first time that it is possible to formulate water-based muds using inexpensive nonmodified and commercially available silica nanoparticles and that these muds significantly reduce the invasion of water into the shale. The addition of silica nanoparticles to water-based muds may offer a powerful and economical solution when dealing with wellbore-stability problems in troublesome shale formations.