Steam Assisted Gravity Drainage = SAGD “Steam-assisted gravity drainage (SAGD; “Sag-D”) is an enhanced oil recovery technology for producing heavy crude oil and bitumen. It is an advanced form of steam stimulation in which a pair of horizontal wells is drilled into the oil reservoir, one a few metres above the other. -wikipedia
The Solids Control Process
Primary Solids Control
Both types of rigs used in SAGD have shale shakers mounted at the drilling rig itself which make the initial solids separate. Rigs with central sites are fairly similar to other drilling rigs; however, the rig transfer tank on which the shakers are mounted moves with the substructure and derrick. Transfer tank capacity is typically no more than 15m³. The majority of the solids control processing occurs some distance away at a central site that remains fixed in place and is connected to the rig with an umbilical cord, sometimes called the suitcase. The suitcase carries electricity, drilling fluid, air, steam, water and information about operations between the rig and the central site. The central site tank system volume is typically 100m³.
Excess fluid loss is discouraged and can cause a problem at the transfer tank shakers for two main reasons:
- Insufficient shale shaker capacity to handle the solids loading;
- Reduced screening ability caused by oil coating.
To ensure adequate shale shaker capacity, maximum anticipated solids loading must be known. For example, with one operator’s plan, the easily drilled surface formations are control drilled so that the rate of penetration (ROP) is limited to 40m/hr. With 661mm bits, this controlled drill rate equates to over 35ton. /hr. of solids reporting to the shale shakers. This will be the maximum loading on which all shale shaker sizing calculations are based. Naturally, volumes decrease in intermediate and production zone drilling. Intermediate hole sizes start at 311mm and are opened to 444mm, but ROP is controlled at less than 50m/hr. There is no industry standard formula that calculates how many shale shakers, or type of shale shaker, will be needed for this scenario. Early attempts at processing the solids with one shale shaker at the transfer tank quickly demonstrated the need for extra shale shaker capacity. Field experience has shown that anything less than two shakers is insufficient. Most SAGD rigs have adopted this practice resulting in dryer discharges and overall improved solids control performance.
During production zone drilling the formations may start to flow. Regardless of the number of shale shakers mounted on the transfer tank, if a hydrocarbon-bearing formation starts to flow it can impact the shale shaker’s ability to screen. Produced oil (bitumen) easily adheres (accretes) to most shaker screens and other surfaces and must be battled with steam, soap, brushes, and in severe cases scrapers and shovels. Early systems and fluids made little provision for dealing with this produced oil which can completely coat the shaker screens resulting in excessive fluid loss.
Self-contained rigs that house all the solids equipment in one room also use four shale shakers, but they are mounted in-line. The flow can be distributed to all four shakers simultaneously via a common header trough. Alternatively, the shakers can be configured for separation in series. For example, two shakers may be fitted with 50 mesh screens for primary solids removal. The screened fluid is collected in a separate compartment and then pumped to the remaining two shakers fitted with finer shaker screens (e.g. 180 mesh).
Secondary Solids Control
Two shale shakers are sufficient for most central site projects, and as stated this option is available for self-contained rigs as well. When scalping shakers are used correctly there is little issue with solids overloading them; however, regardless of how well the solids control system is matched to the drilling program, free oil can quickly blind shaker screens and cause flooding. It is tempting to run much finer screens at the central site and capture more drilled solids, but field trials have shown that anything finer than 180 mesh is counterproductive due to the economics of screen life. At times it may be possible to screen finer without losing fluid; however, it may not be economical. Experience has shown that shaker screens finer than 180 mesh will last less than 24 hours due to the loading and the abrasive nature of solids. Any variance in fluid, solids, or oil content can quickly lead to fluid loss.
Tertiary Solids Control
While a properly sized and maintained shaker system will extract a large portion of the sand, it cannot remove all of the drilled solids. Decanting centrifuges are needed to further clean the drilling fluid and may also be used to dewater (strip) the remaining solids. Traditional drilling programs may not size the centrifuges to process more than a portion of the rig’s circulating rate. However, this is not so in SAGD operations as the extremely abrasive nature of the sand if left in the drilling fluid can quickly impact all fluid processing equipment and reduce drilling performance. Ensuring that the centrifuges are sized to process at least 100% of the maximum circulating rate in the first pass is the only way to guarantee a chance at removing any remaining drilled solids.
Decanter centrifuge process capacity is based on many parameters, but chiefly on rotating bowl size (diameter and length). In order to process a minimum of 3m³/min, four centrifuges were required. Decanter centrifuges used for the first projects had bowls with 355mm diameter and 1245mm length and were able to process approximately 0.75m³/min each. It was quickly recognized that larger, higher capacity machines were needed. Presently, it is common for centrifuges to have bowls with 533mm diameter and 1829mm length. Each is able to process about 1.5m³/min. This cuts the number of centrifuges required in half. In addition, a variable speed main drive and variable speed back drive allows technicians to fine-tune for desired results in solids dryness, gravitation force (G-force), and feed rate.
While most SAGD projects require only two large centrifuges to process fluid while drilling, many installations have the third centrifuge for dewatering operations. These activities may occur simultaneously. The third machine is also configured to process the whole drilling fluid on the active system when required. This centrifuge is usually placed at the central site for ease of accessibility by service personnel and within convenient pumping, distance to surface storage tanks.
Self-contained rigs also use up to three centrifuges, but they are housed in the same room as the shakers. This design also permits operating personnel ready access to all solids control functions in one convenient area.
The Challenges
Traditional solids control and waste management are challenged by a variety of issues that are faced when drilling well pairs in SAGD. Specific considerations that must be addressed are as follows:
- Heavy loading on solids control equipment and circulating systems;
- Abrasive nature of drilled solids;
- Controlling drilled solids while producing oil;
- On-site conditioning and recycling of fluids;
- Reducing excess fluid disposal;
- Reducing or refining operations for size and functionality.
In addition to these daily operational challenges, the fast pace of rig moves presents other challenges, namely:
- Reducing time to treat fluids and wastes between wells;
- Scheduling manpower;
- Scheduling equipment maintenance.
Early SAGD drilling programs adopted many practices from other drilling operations. Rigs were modified as was thought appropriate and drilling programs were written to address perceived hurdles. This approach alone was not always successful.
SAGD rigs must be able to move quickly from well center to well center. Rig types fall into two main classifications: 1) Rigs that move core activities and use a central site for support functions. The substructure, derrick, pipe racks, and transfer tank are the major components that move between wells. 2) Self-contained rigs house all rig equipment including solids control functions on the rig. These rigs move intact from well to well while on a pad and are disassembled only when moving to another location.
Nature of Drilled Solids
SAGD drilling operations in North-eastern Alberta encounter abrasive sand. This sand ranks 7-8 on the Mohs Hardness Scale (Table 1).
| Mohs Hardness Scale | ||
| Hardness | Mineral | Absolute Hardness |
| 1 | Talc (Mg3Si4O10(OH)2) | 1 |
| 2 | Gypsum (CaSO4·2H2O) | 3 |
| 3 | Calcite (CaCO3) | 9 |
| 4 | Fluorite (CaF2) | 21 |
| 5 | Apatite (Ca5(PO4)3(OH-,Cl-,F-)) | 48 |
| 6 | Orthoclase Feldspar (KAlSi3O8) | 72 |
| 7 | Quartz (SiO2) | 100 |
| 8 | Topaz (Al2SiO4(OH-,F-)2) | 200 |
| 9 | Corundum (Al2O3) | 400 |
| 10 | Diamond (C) | 1500 |
This abrasive sand is found predominantly in production zones and can cause severe erosion in fluid processing equipment, including among others: downhole tools, downhole motors, surface process pumps, and associated piping. Shale shakers and centrifuges remove a huge portion of this sand but are not immune to wear either. Early solids control operations underestimated the detrimental effects of these abrasive solids and tried to fine screen at the rig shakers, resulting in excess fluid loss and poor screen life. Screening in stages, i.e. coarse mesh at the rig and finer screens at the central site alleviated this to some extent. By following this practice monthly shaker screen consumption on installations with four shakers has decreased from 80 to less than 40.
Initial systems used small bowl centrifuges rotating at high speeds generating up to 2,200 G-forces. At these G ranges the machines made excellent density cuts and produced dry solids discharges; however, wear on rotating parts was high. Some units required replacement after a few weeks of usage. To help alleviate this, most installations now use larger bowl machines with variable speeds to achieve good separation and dry discharges. These larger bowl machines operate in G ranges less than 1,000 (sufficient for separating sand from low viscosity fluid). Even at these lower G-forces solids dryness is not compromised because these machines can vary differential speeds via back drive settings, thereby increasing solids’ residence time within the bowl.
Bitumen in Drilling Fluid
While drilling through horizontal sections the bitumen may start to flow from targeted production zones. This may cause problems both downhole and at the surface by accreting to process equipment. Bitumen accretion not only reduces fluid hydraulic capacity by coating pipes but also impacts solids’ control performance and can create waste management issues by contaminating otherwise benign solid and liquid streams. Bitumen not only coats shaker screens and circulating equipment but can plug centrifuges causing downtime and adding costs by increasing the maintenance time on this equipment. The bitumen also increases fluid aeration, causing pumps to the airlock and reduces the effective volume of surface tanks. Keeping the bitumen in situ reduces surface contamination problems; however, it is nearly impossible for all of it to remain in place and/or control the amount released while drilling.
Once downhole temperatures reach about 25 °C, bitumen may start to flow. Early systems quickly recognized that maintaining low circulating temperatures would reduce the amount of bitumen released. Initial attempts to keep the fluid cool consisted of an extra mud tank in which dry ice or liquid nitrogen was added prior to pumping downhole. This had its drawbacks including high cost and unpredictability inaccurate control of fluid temperature. The technology has evolved into the use of specialized cooling equipment such as glycol circulating systems and heat exchangers. While lower fluid temperatures aid in reducing bitumen intrusion, they can also impair desirable flow and shear-thinning characteristics of drilling fluid which occurs at higher temperatures.
Currently, significant research is focused on developing drilling fluids to minimize bitumen intrusion. Drilling fluid technology has evolved to the point where some drilling operators choose not to utilize cooling technology.
Drilling fluids may be categorized according to the means by which they deal with the bitumen.
- Encapsulating fluids
- Emulsifying fluids
As their names imply, encapsulating systems are designed to encapsulate bitumen with polymeric additives, while emulsification systems are designed to blend the bitumen into the water phase. One such emulsification system also incorporates a cleaning agent to aid in releasing oil once it reaches the surface2. Each system has its own merits beyond the scope of this paper; however, each system when operated properly aids in reducing the accretion of bitumen to surface processing equipment. A reduction in aeration is also seen.
On-site Fluids Conditioning
Early programs used fresh drilling fluid for each section. Once a section was drilled the fluid was completely or partially dumped into earthen sumps. The fresh fluid was added to reach desired properties for the next drilling section. This resulted in large volumes of fluid for storage, treatment, or disposal.
Along with the introduction of drilling fluids designed specifically for SAGD operations, and thanks to enhanced solids control efficiency, the number of wells that can be drilled with the same fluid has increased. It is not uncommon to reuse the same fluid four times before complete change out is required. Some projects have managed to successfully use the same fluid up to six times.
Reducing Excess Fluid Disposal
Even though the amount of solids generated by drilling larger hole sizes has increased, the volume of liquid waste associated with them has decreased in proportion. This is due to more proactive treatment practices, namely dewatering of spent drilling fluid. A few operators have open-pit mines nearby, readily available for liquid waste disposal. However, even these operators proactively foster good environmental stewardship by modifying their practices to reduce waste volumes. For operators that do not have convenient access to such options, the added cost of waste transportation to injection wells has prompted more aggressive practices. A by-product of this proactive leadership is reduced liability and lower transportation costs. Dewatering (stripping) of drilling fluids is the most readily available option that can have the most immediate benefit.
Once drilling fluid is deemed unsuitable for further use, it is dewatered by injecting a polyacrylamide mixture and flocculants as it enters a centrifuge. This practice produces two phases from the centrifuge; relatively clear water and a stackable solid paste. Depending on the quality, the liquid phase may be reused as make-up water in drilling or production fluid.
If the injection is the only option for liquid waste disposal, then the fact that only water is being injected reduces the risk of jeopardizing the integrity of the injection well. At the very least the removal of solids from dewatering has reduced the volume of fluid for disposal, thereby decreasing haulage costs.
Typical chemical consumption during dewatering operation is approximately one sack (25kg) of a polyacrylamide type for every 10-15m³ of drilling fluid. Usually, 1-2 sack(s) of a calcium additive is also required to properly dewater. These ratios may vary slightly depending on fluid properties.
Reducing or Refining Operations
Many aspects of the drilling program for SAGD have evolved with experience and refined practices. Most SAGD projects have increased location size to accommodate extra activities at the drill site; however, the number of centrifuges has decreased or has been repackaged to occupy less space. Original systems used up to five centrifuges. As noted earlier, the advent of larger bowl centrifuges meant fewer are needed for the same task. In addition, the method of deploying them in conjunction with waste collection systems has been engineered for better efficiency as well. Two examples are cited below:
- Pad rigs with central process sites incorporate a solids collection bin and support stands into a single piece of equipment known as a combination stand or combo stand. Up to three large centrifuges can be mounted on a single stand. The stand also contains the solids discharged from the centrifuges and the shale shaker in the same bin, reducing the footprint of the central site area. The collected solids are removed with a front-end loader. The loader’s tires never contact the discharged solids and therefore there is less chance of the loader tracking material onto the location.
- Self-contained rigs further reduce the footprint needed by housing all solids control equipment in a single room. Discharged solids are transported from the solids control room (located on an upper level) via screw conveyors to bins located at ground level.
Reducing Waste Treatment Time Between Wells
Some SAGD pad operations have multiple drilling, coring, and completion activities occurring concurrently. There is little time for routine maintenance and housekeeping procedures between wells, therefore communication is important in order to make sure all services are coordinated in preparation for the next drilling activity. Most rigs are able to move between wells on a pad in four to five hours, and self-contained rigs in less time than this, leaving little time for fluid change out or fluid reconditioning.
Standard solids control practices are ongoing during drilling; however, dewatering operations may be concurrent while drilling and are accelerated between moves. One large centrifuge can dewater 10-12m³ per/hr of fluid. For example, if 100m³ of fluid requires dewatering, it will take between four to five hours with two such machines. This means that spent fluid can be completely treated while a rig moves between wells. It is not uncommon to dewater between 30-60m³ per day as routine practice while drilling is ongoing. This thereby reduces the amount requiring dewatering at the end of a section.
Scheduling Manpower
Unlike traditional drilling operations, SAGD projects drill virtually non-stop. Most wells on a pad are batch drilled (all surface holes are drilled, then all intermediates, then all horizontals), and rig personnel has little or no time to monitor solids control equipment. This task falls to the solids control companies to supply qualified field service technicians to run this aspect of the operation.
This created a manpower gap for qualified solids control technicians in Western Canada. With the ever-changing nature of SAGD operations and so many new projects starting up (29 companies are currently active in SAGD and heavy oil), many service companies are forced to hire extra personnel and fast-track classroom training prior to field exposure and on the job training. It is beneficial to coordinate the technicians’ schedules with the remainder of the rig site personnel in order to develop a close working relationship and good communication.
Some early projects required up to three technicians per shift to effectively manage the solids control and dewatering demands. However, with the introduction of large bowl centrifuges, more concise equipment packaging, and on-site experience, this number has been reduced. Currently, most SAGD projects require only one field service technician per 12-hour shift; however, end-of-pad moves may require extra personnel.
Scheduling Maintenance
Due to the nearly continuous use of the equipment and the abrasive nature of the sand, it is imperative to establish an aggressive and proactive maintenance schedule. Shaker screens are checked constantly and repaired or replaced as needed. Centrifuges and feed pumps are monitored for any decrease in inefficiency. Minor inspection is done daily and minor lubrication at the end of every section drilled. A more thorough inspection and service occur weekly whereby the wear on rotating parts is measured and recorded for trending.
This monitoring has fostered centrifuge and centrifugal pump rotating assembly change-out policies to be implemented as standard procedures. This is in direct response to the wear seen with continuous use, and as a result of lessons learned from the proactive maintenance program. Under this policy, operators incur the cost of trucking and replacement, while the equipment supplier incurs the burden for wear and tear. The maintenance program has worked very well and keeps the solids control equipment at optimum performance, greatly reducing or eliminating downtime. Additionally and as a result of this, modifications and adjustments to rebuilding practices can be reviewed for effectiveness. Upgrades are incorporated with little or no interruption of service. Since many of these changes are not noticed by visually inspecting the equipment, the benefits of these design enhancements are only seen in the form of reduced repair costs and increased reliability.
Another maintenance program has been implemented for shale shakers. Since shale shakers are the first line of defense for good solids control, some SAGD operators have contracted shale shaker manufacturers to inspect and maintain rig-owned shakers. The benefits they reap from this minor cost are longer equipment life and better performance. Reports of increased screen life and decreased downtime have led these operators to incorporate this service into their standard operations.
