Natural gas production from organic shale is one of the most rapidly expanding trends in North America's onshore oil and gas exploration and production today. In some areas, this has included bringing drilling and production to regions that have seen little or no activity in the past. Advances in horizontal drilling technology and hydraulic fracturing have made shale gas/oil production economically viable.
Haynesville and Marcellus shale plays are among the most active shale plays in the United States. The potential for production from these shale plays, coupled with other unconventional shale gas plays, is predicted to contribute significantly to North America's energy outlook. Although drilling experience has been gained since the development of these shale plays, we are still in the early stages of the learning curve for shale gas drilling. Due to its proven performance parametrics and advantages, invert emulsion drilling fluid, is often the preferred drilling fluid or "mud?? used to drill the horizontal sections of the wells in Haynesville and Marcellus shale plays. However, water-based drilling fluid (WBM) has also been used and usage is increasing in horizontal sections of the Marcellus wells due to its technologically enhanced performance and environmental advantages. A comparative analysis was performed between invert-emulsion-based and water-based drilling fluids used in Haynesville and Marcellus shale plays to assess their performances and to identify the key challenges with both fluid types. The analyses include mud chemistry, drilling days, mud weight and well architectures such as hole sizes and casing sizes as well as depths of the casing shoe. A statistical analysis of drilling performance (P10, P50, and P90) was also performed to evaluate drilling days for wells of various depths of different operators over the past few years with different fluid types.
The analysis of 238 horizontal wells drilled in Haynesville shale play between 2006 and early 2011 shows that there is a continuous improvement in drilling performance over the years. This improvement is more pronounced in the wells drilled with oil-based drilling fluids (OBM). The analysis also shows that some operators drill the wells of similar depths much faster than others. Seepage losses and controllable kicks were also identified as some of the key issues in both Haynesville and Marcellus shale drilling. Although, laboratory results show that the clay content and reactivity of both Haynesville and Marcellus shale are very close to each other, the same WBM systems have shown much better performance in Marcellus shale drilling than in Haynesville shale play. The effects of high temperature and high pressure of the Haynesville shale formation on inhibition capabilities of water-based drilling fluids are among the key factors that have limited the performance of WBM in Haynesville shale drilling. Higher well depths and the increased drilling days in Haynesville shale play result in much more exposure time of the wellbores to drilling fluids, and are the key factors that resulted poor performance with WBM systems.
Ji, Lujun (M-I Swaco) | Guo, Quan (M-I Swaco) | Friedheim, James E. (M-I Swaco) | Zhang, Rui (China University of Petroleum Huadong) | Chenevert, Martin E. (University of Texas At Austin) | Sharma, Mukul Mani (University of Texas At Austin)
Although key shale gas plays vary considerably in terms of reservoir pressure, temperature, mineralogy, and in-situ stresses, the principal drilling-related issues are wellbore stability, shale inhibition, hole cleaning and rate of penetration. Because many of the shale reservoirs are in either environmentally sensitive or densely populated areas, stricter environmental regulations will require new types of environment-friendly water-based drilling fluids. The traditional shale inhibition method through either chemical inhibition or use of invert emulsion drilling fluid is not enough to satisfy the stricter environmental requirements.
This paper focuses on the lab techniques and the performance results of evaluating and analyzing an innovative water-based drilling fluid system containing nanoparticles as a physical shale inhibitor. The physical shale inhibition is achieved by plugging the pores and microfractures in shale with nanoparticles and thus preventing water invasion into the shale. A series of transient pressure penetration or flow-through tests, also known as shale membrane efficiency tests, were performed to evaluate water invasion rates into various shale core samples, with initial brine permeabilities varying from less than 1 nD to over 100,000 nD. Permeability reduction was used as a proxy of water invasion reduction and the effectiveness of plugging of pores and microfractures in shale by the nanoparticles. Many orders of permeability reduction were consistently observed for the drilling fluids with nanoparticles.
Pressure increases in the near-wellbore region due to water invasion during a given time also were analytically calculated using the permeabilities for various fluids which were interpreted from these transient flow-through tests. These pressure increases then were compared to illustrate the approximate impact depth of water invasion and give an indication of shale stability and shale inhibition performance of these drilling fluid systems.
Test results and pressure increase analyses showed that this new water-based drilling fluid with nanoparticles provides an entirely different type of shale inhibition by physically plugging pores and microfractures in shale and meets the strictest environmental regulations for shale gas drilling. The tests also showed that although nanoparticles alone may be effective in preventing water invasion into shale samples with no microfractures, the combination of properly formulated drilling fluid and nanoparticles of appropriate size and concentration is the key to prevent water invasion into shale gas core samples with or without microfractures.
Depletion of many conventional oil and gas reserves and increasing energy demand have heightened the importance of developing techniques to effectively and efficiently drill gas/oil shale. Traditionally, shale is considered as hydrocarbon source rock and/or seal rock only; some shale plays are now recognized as major unconventional hydrocarbon reservoirs. Worldwide, likely recoverable shale gas reserves exceed 250 Tcf by some estimates, with over 10 times that speculated to be in place. In North America, shale gas has been one of the most rapidly expanding trends in onshore domestic natural gas exploration and exploitation (Sandrea 2006).
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.
Nanotechnology has been successfully applied to a variety of products including electronic circuitry, material composites, medical and even consumer goods. Other than a few crossovers, the utility of nanotechnology in the oilfield is still a subject
of discussion as well as debate. Noted efforts by universities and consortiums into such areas as nanosensors, nanomarkers or the more esoteric nanobots to provide valuable data regarding the reservoir are of great focus due to their large potential return on investment, but have yet to yield substantive products. By contrast, efforts into drilling applications of nanotechnology such as drilling fluids are less known.
This paper will review recent works on the application of nanotechnology in shale stabilization, high-temperature tolerance and viscosity modification. This paper will also discuss results from projects which utilize graphene (and graphene derivatives), carbon nanotubes (CNT), nanosilica and other nanochemistries to achieve and enhance the performance of drilling fluids in the applications mentioned above. Further discussion will address some of the concerns and pitfalls of
sourcing and using commercial "nano" products as well as review current HS&E perspective on this new area of chemistry for the oilfield.
As an industry, we are still in the early stages of the learning curve for shale gas drilling although many shale gas wells have been drilled in recent years. Data from over one thousand wells drilled in the Maverick basin since 2003 were retrieved from an internal drilling database. Among them are over two hundred horizontal wells from the Eagle Ford shale play drilled by 31 different operators between 2008 and early 2011. The analyses of drilling performance data of these horizontal wells offer the establishment of general practice guidelines and recognition of opportunities for improvement in Eagle Ford shale drilling.
Oil-based drilling fluid, or "mud?? (OBM) is a typical drilling fluid type currently used to drill from the surface casing shoe to the total depth (TD) in the Eagle Ford shale play. However, water-based mud (WBM) has also been used since the development of the Eagle Ford shale play. A comparative analysis was performed between oil-based and water-based drilling fluids to assess their performances and to identify the key challenges and potential areas for improvement when drilling in the Eagle Ford shale. The analyses included mud chemistry, drilling performance, mud weight and well architectures such as bit sizes, casing sizes and depths of the casing shoe, as well as lateral length. A statistical analysis (P10, P50, and P90) was also performed to evaluate industry-wide drilling performance such as drilling days for wells of various depths. Comparisons were made among different drilling fluid types and different operating companies.
The statistical analysis shows that although overall performance of water-based drilling fluids lags behind that of oil-base fluids in Eagle Ford shale drilling, a certain WBM system shows promising performance close to that of oil-based drilling fluids. The analysis shows that there is a general trend of decreased drilling days per footage over time and a large variation in total drilling days for similar well depths and trajectories. This indicates that although the drilling industry as a whole has improved drilling in the Eagle Ford shale over the years, there is still a large opportunity for improvement. One interesting finding is that some operators can drill wells in fewer days than the industry average even though their drilling fluid cost is slightly more expensive than the industry average. As a result of reduced drilling time, their overall drilling costs are reduced.
Lab test results with different fluid types show that the failure mechanism and shale-fluid interaction of the Eagle Ford shale is different from dispersion or swelling which are typical of traditional shales. The analyses and results of this study on drilling performance data provide lessons learned and general guidelines for current drilling practices and opportunities for improvement such as drilling fluid selections, mud weight, and well architectures in the Eagle Ford shale play.
Riley, Meghan (M-I Swaco) | Young, Steven (M-I Swaco) | Stamatakis, Emanuel (M-I Swaco) | Guo, Quan (M-I Swaco) | Ji, Lujun (M-I Swaco) | De Stefano, Guido (M-I Swaco) | Price, Katherine (M-I Swaco) | Friedheim, Jim
Shale-gas plays and other unconventional resources have gained significant importance worldwide. Historically, synthetic-base drilling fluids (SBM) are used in these plays when no environmental concerns are in place and are preferred when wellbore stability is necessary. In this paper, we study the use of an improved water-base drilling fluid (WBM) that is simple in formulation and maintenance that shows excellent rheological properties, maintains wellbore stability, and a good environmental profile. A combination of well-known and economically affordable materials is combined with new technology to achieve desired rheological properties and wellbore stability.
The use of nanoparticles to decrease shale permeability by physically plugging nanoscale pores holds the potential to remove a major hurdle in confidently applying water-base drilling fluids in shale formations, adding a new advantage to the studied fluid. Silica nanomaterials were investigated for this purpose. Due to their commercial availability, these materials can be engineered to meet the specifications of the formation. Characterization of the nanoparticles was completed with Transmission Electron Microscopy (TEM), dynamic light scattering, and X-ray photoelectron spectroscopy. Rheological properties and fluid loss are studied together with other important properties such as shale stability and anti-accretion properties. The authors will describe new laboratory methods used to investigate these properties, from a modified API fluid loss test to the Shale Membrane Test that measures both fluid loss and plugging effects and illustrate additional future research that includes adding reactive species, and anchoring them to the pores, thus stabilizing the shale further.