The second panel of the workshop included four presentations that focused on the well completion and stimulation technologies and operations utilized in the Gulf of Mexico and in the Pacific offshore environments, as well as strategies to address challenges and manage risks in these environments. The panel and large-group discussion were moderated by George Wong, University of Houston.
Offshore Well Completion and Stimulation Operations Using Hydraulic Fracturing and Proppant: Technologies, Operational Practices, Challenges, and Risk Exposures
Dennis McDaniel, Anadarko Petroleum Corporation
McDaniel explained that reservoir characteristics determine well completion requirements in the offshore environment. These characteristics include porosity (i.e., void space between the sand grains of the rock), permeability (i.e., interconnected void space and the ability of fluids like oil and gas to flow through that rock matrix), pressure, and temperature. He noted that completions are done in either unconsolidated or consolidated sands. In designing offshore completions, sand control is the central objective. Typically, unconsolidated sands are shallower, younger Cenozoic-era rock formations (Pliocene and Miocene in age, or between about 3 and 23 million years old) with high-permeability reservoirs, while consolidated sands are deeper, older Cenozoic rock formations (Oligocene, Eocene, Paleocene in age, or between about 23 and 66 million years old) characterized by higher pressures and temperatures and lower-permeability reservoirs. As a result, different completion techniques are used in each of these environments. Gravel packs and frac packs can be used in unconsolidated sands for sand control; however, in consolidated sands, a fracture stimulation (i.e., hydraulic fracturing) is performed to aid production of oil or gas from the well (see Figure 4.1), according to McDaniel. He remarked that all three techniques have been applied successfully for years in the Gulf of Mexico.
McDaniel explained that in a gravel pack (also known as an annular pack or a high-rate water pack), one fills the perforation tunnels and the screen annular volume with sand. This significantly reduces the amount of formation sand flowing into the wellbore. Gravel pack technology has been used for more than 50 years and historically represented 100 percent of the sand control well completions in the Gulf of Mexico, though, due to technological evolution, it is now used in less than 10 percent of completions. A frac pack induces near wellbore fracture geometry that is then filled with proppant to bypass near wellbore damage from drilling and to extend the proppant pack a farther distance from the wellbore into the reservoir (approximately 10- to 60-foot fracture half-lengths1). This technology is not, however, intended for significant reservoir stimulation like hydraulic fracturing. The frac pack has been in use for 25 years and currently is used for approximately 75 percent of the completions in the Gulf of Mexico, McDaniel said. It offers greater reliability and reduced interventions than the traditional gravel pack. Hydraulic fracturing is a technique used for stimulation in consolidated reservoirs. While this technique has been used onshore for decades, it has only been utilized offshore for approximately 10 years and is deployed in less than 10 percent of Gulf completions. He noted that hydraulic fracturing minimizes the number of wells needed to develop a reservoir (less environmental impact) and allows for the development of natural resources not previously considered commercially viable. McDaniel emphasized that all three completion techniques are covered by existing operational and environmental regulations and permits.
McDaniel then described the step-by-step process for frac pack sand control completion operations. Gel and water are mixed together into a viscous oil-like substance, and then proppants and additives are blended into the gel, creating a Jell-O-like substance. This substance is pumped down hole, and the fluid transports proppant into the created fracture. Once the fracture is filled with proppant, the pumping stops. Aided by the additives, the fluid reverts to a liquid, the fracture closes onto the proppant, and the fluid flows out of the well during production. The proppant that has been trapped in place during this process provides a highly conductive channel
1 The fracture half-length is the distance from the well to the tip of the fracture.
for the reservoir fluids to flow through toward the wellbore, increasing the well’s productivity. He added that mini-fracs (small fractures created using fracturing fluid without any proppant to determine stress magnitude) are sometimes used in the offshore to learn about the reservoir and aid in design of treatment.
McDaniel next provided an overview of well treatment volumes. For example, in unconsolidated sands in the offshore conventional environment, less than 5,000 barrels2 of proppant may be needed in the main stage of treatment. In consolidated sands in the same environment, more than 5,000 barrels may be needed per stage, with two to five stages likely. For the onshore unconventional environment, main treatment volumes may exceed 30,000 barrels3 per stage, with more than 10 stages possible. He emphasized that reservoir properties dictate what each well needs in the design stage.
The technologies used onshore as compared to technologies used offshore for well completion vary, according to McDaniel. He reiterated that in the onshore, the primary driver is to create fractures in tight rock for productivity, while the primary driver in the offshore environment is sand control. He added that gravel packs, frac packs, and hydraulic fracturing can be used onshore or offshore. However, another difference between the uses of the technologies is that high-volume hydraulic fracturing of unconventional formations onshore is not yet occurring offshore in the Gulf of Mexico. Echoing what Evan Zimmerman, Offshore Operators Committee, said in a keynote address at the beginning of the workshop, McDaniel explained that concerns about implications for drinking water aquifers are not pertinent to offshore operations, and the remoteness of offshore operations ensures minimal public impacts from completion activities.
Approaches in the Gulf of Mexico: Technologies, Operational Practices, Challenges, and Risk Exposures
Michael Schexnailder, Halliburton
Schexnailder provided an overview of land-based fracturing operations prior to discussing stimulation vessels and their operations in the Gulf of Mexico. He explained that for onshore operations, water, proppant, and additives are first blended to generate the stimulation fluid that is delivered to high-pressure pumping units. These units then send the fluid down into a well. Monitoring of this complex process is done in real time and on-site in a technical command center. For offshore operations, all of this equipment is built into the vessel, which has five zones (see Figure 4.2): (1) fluids and bulk storage of proppants are on the bottom; (2) an active storage section for proppants is above; (3) the fluids from below deck are added to the proppant in the blender section in the middle (with additives specific to offshore stimulation); (4) the blended fluid is delivered to high-pressure pumps; and (5) the fluid is sent to the high-pressure flexible Coflex hose (approximately 400 feet in length) mounted on a reel and transferred to the drill ship. On a vessel such as the Stim Star IV, for example, a typical job for a consolidated frac pack stimulation would have approximately 3 million pounds of proppant and 40,000 barrels of fluid, according to Schexnailder. Jobs are pumped at a rate of 25 to 45 barrels per minute, and the pressures range from 8,000 psi to 13,000 psi.
Schexnailder explained that the vessel is safely placed in close proximity to the drill ship through the use of dynamic positioning. Dynamic positioning utilizes a system of thrusters and
2 Equivalent to 210,000 gallons.
3 Equivalent to 1.26 million gallons.
high-precision measurement and monitoring systems to ensure that the vessel stays in a specific location. The U.S. Coast Guard routinely inspects the dynamic positioning system. Redundant safety measures include the use of a global positioning system, optics, and radar.
It is important that measures to ensure operational safety begin far in advance of the time that the vessel arrives on location, according to Schexnailder. There is an initial coordination of materials and plans to load them onto the vessel, as well as coordination between the vessel captain and the drill ship regarding weather conditions that could delay the job. Once the vessel arrives on location, the dynamic positioning system is checked. Next, a pre-job meeting occurs in which all of the parameters of the stimulation and monitoring operations are discussed and a system pressure test is conducted. The stimulation is then ready to begin and will range in duration from 8 to 18 hours, he explained.
Schexnailder emphasized the importance of communication paths; the stimulation vessel captain remains in constant communication with the drill ship captain regarding weather or dynamic positioning issues because vessel safety is their primary operational concern. Personnel on the stimulation vessel are also in constant contact with the drill ship, maintaining stability while as much as 25,000 pounds of material is moving per minute. He remarked that if the dynamic positioning system cannot hold its position, due to weather or other performance issues, the job can be shut down, with the hose placed back on the stimulation vessel and the vessel departing the location within approximately 30 minutes. Alternatively, in an emergency situation, the hose can be disconnected from the stimulation vessel in approximately 5 seconds, allowing the vessel to depart immediately. Schexnailder noted that it is possible to put the hose back into service in the future if it passes inspection and testing.
In the deepwater Gulf of Mexico, 95 percent of the stimulation fluid is composed of seawater or brine, Schexnailder explained. The fracturing fluids have high viscosity to reduce potential leak-off and to deliver the proppant to the appropriate parts of the fracture. The additives (i.e., non-priority pollutants subject to static sheen and oil and grease testing from the industry) are then used to degrade the viscosity down to that of water, at which point produc-
tion begins in the well and any fracturing fluids that would be produced go through and into the production facility to be processed.
Schexnailder commented that stimulation vessels in the Gulf of Mexico are of limited capacity: only five vessels now operate and conduct approximately 100 completions offshore per year. Because these logistics are challenging, he suggested that companies mobilize modular components of a stimulation vessel and place them onto an offshore supply vessel with the dynamic positioning system already in place in order to fill a short-term demand for stimulation services.
Approaches in the Offshore Pacific: Technologies, Operational Practices, Challenges, and Risk Exposures
Mike Hecker, ExxonMobil Corporation
Transitioning from a discussion of the offshore environment in the Gulf of Mexico to that in the Pacific, Hecker remarked that the rock formations are the main difference between the two. In the Gulf of Mexico, the sandstone in many locations is so weak that it falls apart, and sand control is the primary focus of well completion activities in this region. In the Pacific, the rock is hard and contains natural fractures. Some of these fractures are damaged while drilling the well, so the major focus in this region is to stimulate and to remove damage.
Most wells in the offshore Pacific are simple, cased and perforated completions. To perforate a well, Hecker explained, one perforates into the reservoir through the steel casing, through the cement, and into the formation. This process allows the oil and gas to enter the wellbore and establishes a connection to the natural fractures. Fractures that have been damaged from drilling can then be cleaned up and carbonate material can be dissolved with acid. Because the wells will not always flow by themselves, artificial lift can be used to bring a well online. He noted that of the 745 offshore California wells producing in 2013, only 22 hydraulic fracturing stimulations were recorded, indicating that little fracturing is occurring in the offshore Pacific environment. The majority of well stimulation activities in the offshore Pacific involve matrix acid jobs.
Hecker indicated that typical acid volumes are between 100 and 150 gallons per foot of perforations in the offshore Pacific. So in a short interval of approximately 100 feet, 15,000 gallons of acid would be used. The acid treatment volumes for jobs in California are drastically less than those for unconventional fracture treatments onshore (e.g., 600 to 6,000 versus 30,000 to 50,000). However, the challenge in the Pacific is to divert the acid so that it treats the entire interval, and thus the entire well, instead of just the top perforations. He suggested that one way to address this problem is by using a diversion technique. With this approach, the injection rate is continuously increased (without fracturing) to force the fluid to more and more of the perforations. If that approach proves insufficient after starting to pump acid, ball sealers can be dropped into the wellbore. These balls will seal each treated perforation, diverting the acid to other perforations so as to treat the entire interval. Hecker commented that another technique, selective perforating, is more appropriate when contrasts in permeability exist. The lowest permeable (i.e., most difficult to stimulate) interval is perforated first, and a multi-treatment method is used (i.e., as the acid is pumped down, a thick gel [a diverter] is added) to open up more perforations into which the acid can flow. A third option is to run
coiled tubing across the perforations and jet acid up and down the wellbore. While this does not ensure injection into the formation, it does ensure that the acid is placed at the location of the coil. This technique is most appropriate for cleaning up drilling mud or removing damage. According to Hecker, new technologies from the unconventional arena, such as ball-activated sleeves (see Figure 4.3), are emerging in the offshore Pacific to ensure that acid is placed in each individual zone, treating the full interval.
Well Integrity Considerations for Technology Deployment and Practice
Lisa Grant, Bureau of Safety and Environmental Enforcement
Grant highlighted the variability in the terminology used throughout the oil and gas industry. For example, while some do not use the phrases “well integrity” and “safety” interchangeably, Grant prefers to treat them as the same. Well integrity means having control over a well by maintaining dual barriers and understanding its state. Thus, references to well integrity imply safe operation in which unexpected well control events and pollution events do not occur. She also clarified that fracturing is done in completions, not during drilling, and emphasized the importance of managing both activities. In the drilling stage, drilling and reservoir fluids are maintained in the well and are prevented from propagating into the formation. While there are many unknowns in drilling, completions are performed around known conditions, she said, and the installation of completions is a highly technical, well-planned activity. Because these drilling and completion activities are so different, unique decision-making processes are utilized in each.
Grant explained that when there is a lack of permeability in unconventional formations or when it is important to move past the damage left behind by drilling to achieve better production, hydraulic fracturing is useful. She highlighted the ways in which the development and application of technologies for unconventional formations have ramped up very quickly.
As a result, she cautioned against looking at fracturing design independent from the rest of the well. In other words, well integrity is an integral part of completion design, according to Grant. Evolution in fracturing design chemistry has occurred in the offshore, but the overall process of moving past the damage zone around the well has evolved more slowly than it has in the onshore. Offshore, she explained, it is somewhat easier to ensure that the completions are not outrunning the well integrity.
Challenges in the offshore environment emerge especially in work with deep formations, which call for larger completions with design lives of 20 to 30 years. The industry is working to address such challenges in the overall scope of the operating envelope by considering whether the design life and pressures are appropriate for anticipated production as well as how the metallurgy and seals, for instance, play a role in well construction and long-term maintenance. Because of the extreme conditions offshore, it is even more important to understand the loads and the long-term impacts on well integrity. Grant encouraged considering the entire construction process in order to truly understand risk, instead of focusing solely on fracturing. She remarked that a key aspect of understanding well integrity is the understanding of barrier envelopes. The well and blowout preventer system have to be competent to withstand the pressures and fluids being exerted on them, and a two-barrier system decreases the likelihood of complete failure.
Grant noted that over time the industry has become safer while increasing production and reducing production costs. She emphasized the importance of understanding operating environments and their impacts on well design and unintended loads. She reiterated the importance of properly assessing design changes to ensure that proper barriers are maintained to protect people, the environment, and the asset itself. She added that current regulations focus on ensuring that barriers are appropriately manufactured, installed, and validated as well as that the environment meets the barrier envelopes of what is in use. Grant cautioned against using historical data when assessing risk: different safety measures apply to different places at different times.
An online participant asked if there is consensus on the stimulation of near well fracturing with large bed proppant packs versus far field fracturing and partial layer proppant packs. Wong responded that in the onshore environment, because the formation rocks have no permeability, fractures are long and likely narrow. However, because the rocks in the offshore environment are highly permeable, it is common practice to make wide fractures (i.e., frac pack). Another participant added that the rock determines the types of fractures that emerge, while McDaniel noted that completions are tailored to the specific needs of the reservoir. Another participant asked if it is possible to generalize a maximum fracture length, acknowledging that the fracture length is limited by the hydraulic horsepower and volume available to pump the job. McDaniel responded that it is more reasonable to create a longer fracture in a consolidated reservoir than in an unconsolidated formation. He reiterated that the rock dictates the limits: two formations with similar pressures and volumes can end up with fractures of different lengths. Wong noted that the challenging logistics of the offshore environment can also limit the length of the fracture, and Hecker reiterated that permeability in offshore wells is also a consideration.
A participant asked the panel how often acid dissolution is used both in the Gulf of Mexico and in the Pacific, as well as how often acid injection is used in both the onshore and the offshore environments. McDaniel said that from a Gulf completion standpoint, this can vary according to operator preference, though pre-acid jobs will usually be pumped ahead of the gravel pack jobs. Doing so alleviates near wellbore damage from drilling, cementing, or perforating. Hecker emphasized that whether one is working in the onshore or the offshore, it is imperative to understand what the problem is and what is causing the damage before choosing a stimulation method. In response to the participant’s follow-up question about similar considerations for onshore shale, Hecker said that a bit of acid (or even just pressure, in some cases) is often pumped down the formation at the beginning to try to open up as many perforations as possible.
Another participant asked if there is a unique relationship between the wellbore and the rocks in the offshore environment. Grant said that from a drilling perspective one never wants to lose fluid, yet the permeability of offshore formations provides many places for the fluid to go. However, sealing the formation during drilling to avoid taking on any more fluid can have detrimental effects for production.
Wong asked the panelists if subsea development has different considerations in terms of hydraulic fracturing or in terms of completion more generally. Hecker responded that it is quite easy to diagnose and repair problems on a platform. However, in a subsea well that is in 7,000 feet of water, it is incredibly difficult and can cost tens of millions of dollars to run diagnostics and make repairs. As a result, it is crucial that the subsea well completion is done correctly and can last for at least 25 years.
Another participant wondered how to maintain fracture propagation in a target zone so as to avoid contact with fresh water. Hecker explained that companies correlate core data with physical properties in a fracture model, which helps them to better understand the barriers and to keep the fracture in the appropriate zone. This also helps prevent wasting proppant, Hecker continued. In addition to using models, companies design both perforation locations and fluids and study high leak-off zones in an effort to control the location of the fracture. McDaniel added that more data are usually gathered in the drilling phase in the offshore environment than in the onshore. He cautioned that models are only as reliable as their inputs, so mini-fractures can be used to calibrate an initial fracture design and gather additional information, while after-fracture logs can also be helpful to better design and carry out future completions. Grant said that although groundwater contamination is a valid concern, it is not necessarily a result of fracturing—the well itself can serve as a conduit. To avoid water-related incidents, she encouraged better education about both fracturing and maintaining well integrity. Wong advocated for high-quality wells, despite the associated high costs. He added that access to and visibility of the fracture (through the use of monitoring devices) is better in vertical wells than in horizontal wells.
Continuing the conversation about the use of data and tools for offshore operations, a participant asked what data analytics have revealed about the geological model evolution in the Gulf of Mexico and how this information influences exploration. Wong said that within a relatively immature theoretical background (in terms of conventional development), many analytic tools and measurement devices, and thus more data, have emerged over time in the offshore. He acknowledged that although the industry has much knowledge, it can always learn more to achieve better results and improve production. Grant added that a tremendous amount of data are collected on different types of depositional environments when drilling.
The participant then asked whether companies are prone to protecting information or if they are open to sharing data about the geologic framework to advance operations in this environment. Another participant responded that the geologic model of the Gulf of Mexico is one of the best known of all the sedimentary basins because it has been drilled extensively for so many years. Despite this level of knowledge, the participant explained, there is still always a surprise at the level of a well in a particular play.
In light of the conversation about knowledge sharing and technological improvements, a participant asked when a better advancement for more cost-effective sleeves may emerge. Hecker noted that improvements have been made in the number of treatments that can be done, owing to the limited number of ball sizes; pressure pulsing and radio frequency identification technology are being used to enable automatic opening and closing of sleeves. McDaniel said that the industry will be at a disadvantage until it can increase equipment pressure ratings. He emphasized that communication occurs often, especially for those with both onshore and offshore operations—they share different types of technology and ideas about enhancing operations. Wong noted that sand management may not be addressed with a pinpoint application of fracturing, which means that tools may need to be modified. He asked Grant what challenges would exist for well integrity if such a pinpoint fracturing tool was used for an offshore deepwater application. Grant noted that because increased sand production can lead to erosion, monitoring for potential integrity issues becomes even more important as new issues are introduced and boundaries are pushed. Schexnailder added that there are few unconventional development projects in the Gulf of Mexico, so the potential for them not to go as planned (and the associated implications) is significant, which can be a barrier to introducing new technologies.
An online participant asked how improvements in completion treatment techniques have impacted recovery rates. Hecker said that it is now possible to pull tens of millions of barrels of oil out of a well, all while keeping that well online for 20 years. McDaniel explained that productivity is higher in high-permeable, offshore wells than in conventional land wells. Wong added that making the development of lower permeability formations more economical is the next critical challenge. Schexnailder said that operational efficiency is key for maintaining economic viability of a deepwater or frac pack treatment (i.e., keep the same functionality but re-purpose to establish a more efficient means of delivery). In response to a question from Grant about enhanced recovery, Wong agreed that increasing recovery is important and is thus a consideration in injector design. Tertiary development is another area of interest—McDaniel said that most technological advances occur in the subsea infrastructure because the greatest potential for reserves comes from deeper wells.
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