difference between drilling rig and workover rig pricelist
Workover Rig is available for both onshore as well as offshore Workover purposes at affordable prices. There are a number of companies that manufacture the Workover Rig as well as Rig packages that are required for different kinds of drilling jobs and meet the standards that have been set by the American Petroleum Institute or the API. The Rig packages are shipped worldwide. The rigs are included other than the simple Workover and they include the following:
Workover Rig is known as the Workover the different types of rigs include the offshore and onshore Rig that range from 150 horsepower to 1000 horsepower. Workover rigs have a surface depth that is equipped with diesel engines and transmissions and is available from 8000 ft to 30000 ft. Workover rigs contain a full line of drilling packages. Rig takes into account the skid mounted drilling rigs and the ones that are trailer mounted. Workover skid mounted drilling rigs incorporate the diesel-electric AC/VFD or the DC/SCR drive rigs, mechanical drive rigs and the combination drive Rig that ranges from 1000 horsepower to 6000 horsepower; while the trailer mounted Rig ranges from 450 horsepower to 1000 horsepower.
A lot of Workover Rig uses the double telescopic mast with the help of a single mast and is operated by wide wheel base axels, high strength steel beam, low cross section tires, dual pipeline brakes as well as hydraulic assist steering for the Workover. Rig mast is a double section type and uses a telescopic mast for dual safety protection. The gear shift and throttle of the engine can be remote controlled.
Workover types of Rig are available in the form of the single drum as well as the double drum. The groove ensures the alignment of in place as well as for long life. The optional Workover accessories for the auxiliary brakes include air thrust disc type clutch, brakes for the braking of the main drum, forced water circulating cooling with the brake rims as well as the optional brakes. Workover rigs are centrally controlled with electricity. The other kinds of drilling equipment include drilling equipment, triplex mud pumps, well control equipment; solids control equipment, oil control tubular goods and quality equipment. Work over rigs run casing tools and clean outs inside and outside a hole already drilled.
The cost for drilling and completion rigs plus the associated drilling tools can be a substantial fraction of the total drilling costs, particularly offshore. Properly estimating these costs for inclusion in an authority for expenditure (AFE) is important.
The first three cases used the same well design criteria and equipment (i.e., casing, mud, and logging—with the exception of the rig cost). Case 4 uses the same well in an offshore environment, resulting in the need for a jackup rig. As a result, it is easily seen that careful attention must be given to defining cost for the drilling rig and tools.
Moving the rig into the location before drilling the well and out of the location after it is completed can be a substantial cost item. Jack-up rigs require a fleet of tugboats, while drillships may be able to move themselves onto the location. Many states have published tariffs that specify the allowable trucking charges for various types of moves. Large land rigs are normally transported by truck to the location. Generally, IADC Type 3 and 4 rigs are sufficiently large that they must be transported piecewise by truck. Types 1 and 2 are usually truck-mounted rigs, which reduces the moving time and associated trucking requirements.
Procedures for estimating rig cost can be developed with the rig cost and average moving times. A survey of numerous drilling contractors showed that Type 1 and 2 rigs usually require approximately 4 days for move-in, rig-up, rig-down, and move-out. Type-3 and -4 rigs required 8 days for land and offshore rates, although the elements of this time value are different (i.e., land rigs are transported by truck while jackups are towed by boat).
The cost for move-in and move-out is estimated as the standby rig rate over the moving time (4 or 8 days). The standby rate is slightly less than the day rate for drilling and may include support services, such as crewboats, that would be required for normal drilling operations. This method for estimating the rig moving costs is effective and reasonably accurate. It is not useful, however, in unusual circumstances, such as overseas rig moves and drillsites, requiring helicopter transportation.
Many operators prefer to drill on a footage or turnkey basis. The drilling contractor provides a bid to drill the well to a certain depth, or until a certain event, such as encountering a particular formation, kickoff point, or geopressure. Footage contracts may call for drilling and casing a certain size hole through or to the expected pay zone. Contract clauses may allow reversion to day work (flat rate per day), if a marked increase in drilling hazards (loss of circulation, kick, etc.) occurs. For example, ABC Oil Co. may contract XYZ Drilling Co. to drill a well to 10,000 ft for a flat fee of U.S. $27.50/ft. The drilling company is responsible for all well operations until the contracted depth is reached.
The footage contract defines cost responsibilities for both parties. The operator may pay for all pipe, cement, logging, and mud cost. The contractor is responsible for all rig-associated costs such as move-in and move-out, drilling time, and bits. At the target depth or operation, all costs and operational responsibilities revert to the operator.
This contract arrangement can offer significant advantages to both parties. Operators are not required to staff a drilling department for drilling a single well or a few wells. The drilling contractor, with proper bid preparation and efficient drilling practices, can gain a greater profit than while on straight day-work rates. Possible problem areas for the drilling contractor include:
Perhaps the most common drilling contract is the day-work rate. The contractor furnishes the rig at a contracted cost per day. The operator directs all drilling activities and is responsible for the well-being of the hole. The rig may be with or without crews or drillpipe. In addition, options such as high-pressure blowout preventers (BOPs) or sophisticated solids-control equipment required by the operator must be furnished at his own expense.
Rig selection and cost depend on the well. Although rigs are often rated by their capability to drill to a certain depth, the controlling criterion is usually the casing-running capability (i.e., derrick and substucture capacity). A rig rated for 18,000 ft of drilling may not be capable of running 15,000 ft of heavy 9⅝-in. casing. Therefore, the well plan must be developed and analyzed before rig selection.
Rig costs vary considerably and are dependent on items such as supply and demand, rig characteristics, and standard items found on the rig. Results of a study to compare U.S.-operated rig costs are shown in Fig. 2. The guidelines were the rig’s derrick and structure capacity and disregarded items such as optional equipment that might otherwise be rented for lesser rigs. An interesting point on the illustration is that the over-supply rig costs were reasonably equal regardless of the rig size (i.e., U.S. $6,000 vs. $9,500/day for small to very large rigs).
Standby rates for drilling rigs usually range from U.S. $200 to $500/day less than the amounts shown in Fig. 2. The rates include crews and drillpipe. The costs are used to estimate move-in and move-out charges.
Drilling contracts are either inclusive or exclusive of fuel on the rig. This major contract policy change occurred in the late 1970s when fuel charges increased from $0.20 to $1.20/gal.
Fuel usage is dependent on equipment type and rig. Fuel consumption rates were evaluated in the study previously described for rig cost rates. The results are shown in Fig. 3. The average consumption rate is evaluated as a function of the rig size measured by its ability to run casing.
Water can be supplied in three ways. A shallow water well can be drilled. This method is common in most land operations, but it is not feasible offshore or with deepwater tables on land. Water can be transported to the rig by means of truck, pipelines, barges, or boats. In addition, offshore rigs can use seawater.
Establishing a bit cost depends on the number, size, and type of bits and their respective cost. The bit type, size, and number should have been previously defined in the well plan by the time the AFE is prepared. If the bit is a standard IADC-code bit, published prices are available. Prices are not readily available for specialty bits or for diamond and polycrystalline bits.
Diamond-bit costs depend on the bit size as well as the diamond size, spacing, and quality. In most cases, these bits are made upon demand and are not off-the-shelf items. A rule-of-thumb cost guide for diamond bits is $2,500/in. of bit diameter. For example, a 10-in. bit would cost approximately U.S. $25,000. Salvage values of up to 40%; of the bit cost are often granted on used bits. From a conservative view, many engineers prefer to disregard bit salvage value when estimating bit costs, in case the bit is completely destroyed.
Polycrystalline bits are a staple in the drilling industry. Their physical structure, drilling performance, and cost are significantly different from roller-cone or diamond bits. Sample costs for these bits are shown in Table 2.
A completion rig is a small workover rig that costs considerably less than a large drilling rig. Operators often use these rigs when the completion procedures are expected to require significant amounts of time. The drilling rig is used until the production casing is run and cemented.
Costs for completion rigs can be determined from Fig. 2. Tubing or small drillstring load requirements are used instead of casing capacity. Economic decisions to use a completion rig must also consider the cost of the rig moving onto the location, as well as the daily-rate differences between the drilling and completion rigs.
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Drilling in its broadest sense is any process that involves making a circular hole in a solid material or hard surface using a boring tool. With thousands of applications across industries, drilling is undoubtedly one of the greatest inventions of human civilization.
A drilling machine is any of a variety of devices used for drilling. All types of drilling machines feature a drill bit that removes parts of the material it drills into to make a hole. This drill bit most typically rotates around its axis to achieve this.
- Upright drill press: A heavy-duty cousin of the upright sensitive drill press, it can be operated either manually or using a power source as it is used for larger holes in harder or larger materials.
- Radial arm drillpress: Possibly the most versatile drilling machine in workshops, the radial arm drill press moves over the material that needs to be drilled rather than the operator having to move the material to position it for drilling.
- Special-purpose drillingmachines: These, as the name suggests, are used for special tasks, such as drilling two dozen holes at once (the gang drill and the multispindle drill press, for example) or drilling very small holes (the micro-drill press).
From micro-holes to oil wells and mining tunnels, drills are used for making extensive range of holes. Based on size, we distinguish between three main types of drilling:
Microdrilling: This type of drilling refers to the drilling of holes with a diameter of less than 0.5 mm. For such tiny diameters, drillers use high spindle-speed drills that can revolve at more than 10,000 RPM.
Deep drilling: The sort of drilling that is used in the oil and gas industry, deep drilling refers to making holes that are a lot deeper than they are wide. The ratio between their diameter and their depth is often more than 300:1.
Trepanning: This is a type of drilling where the ratio between diameter and depth is the opposite of deep drilling. Strictly speaking, it is not even proper drilling as it involves a cutting machine removing a wide-diameter disc from a hard surface such as a metal sheet, for example.
Outside construction, workshops and the home, drilling is most popularly used in mining, science—for taking rock or soil samples—water supply, and in oil and gas exploration and production. In these industries, the drilling machines used are a lot larger and fall into one of two categories: percussive and rotary. Based on this distinction, there are two main types of industrial drilling:
Percussion drilling is used in mining operations to break down the rock. Here, the industry distinguishes between down-the-hole drilling and top hammer drilling.
Down-the-hole drilling involves a hammer driven by compressed air along a drill pipe. DTH drilling is used for breaking down harder rocks. In these drills, the hammer is attached to the bottom of the drill string and hits the rock with a high frequency.
Top hammer drilling is another subtype of percussion drilling, which involves s rig with a piston that delivers the percussive force to a hammer as in DTH but here, the drill also revolves around its axis in addition to delivering hammer strikes to the rock that needs to be drilled through.
Rotary drilling is the most popular sort in oil drilling and in gas drilling, and it is also used in mining. There is no hammer action in rotary drilling, but a lot of rotating action, hence the name. The drill bit in a rotary drill spins on its axis to remove bits of rock and create a hole. In modern rotary drills, both the drill bit and the drill shaft—collectively the drill string—spin around their respective axes.
One major advantage of rotary drilling over percussive drilling is that the drill bit can be cooled by adding fluid to the drill shaft. This allows for longer continuous drilling because the drill bit does not need to stop rotating to cool off.
Exploration drilling: This involves drilling for rock sample collection. The purpose of collecting samples is to examine the quality of the mineral resources in the rock. It is also called core drilling, after the shape of samples that are collected. These are cylinders of rock that are removed from the formation with a special-purpose drill that operates like a hole saw.
Technical drilling: Technical drilling encompasses the drilling operations that accompany the development of an underground mine, including drilling for drainage, slope stabilization, and foundation testing before production begins.
Blast hole drilling: This is the process of drilling a hole into the rock and packing it with explosives in order to loosen the rock and make the ore suitable for excavation. Blast hole drilling, sometimes also called production drilling, is used in both surface mining (open-pit) and underground mining, both for exploration and production purposes.
- Face rigs are used to drill mining tunnels and in metal ore mines. The size of the drill used depends on the size of the mine and its depth. Some of these rigs are specifically designed to drill blast holes and others are made to operate in very narrow tunnels. Yet others are designed to drill deep holes and excavate tons of ore.
- Bolting rigs, or mining bolters, are machines that can both drill holes and then install safety bolts in them in the ceiling and walls of underground mining tunnels. Some of these are designed as more versatile rigs that can be used both for drilling holes for safety bolting and for longhole drilling—drilling for ore.
Choosing the appropriate drilling rig in mining depends on a number of factors, including the type of rock that will be drilled into, the size of the mineral prospect, and the sort of hole the miner wants to drill—exploration, blast hole, production hole, or a mining tunnel.
Appraisal: Once the presence of oil and gas has been established, a well is drilled to see whether they are indeed in quantities that would justify commercial exploitation of the field.
Production: Once a prospect has been confirmed as an oil- and gas-bearing field, production wells are drilled in the locations with the greatest concentration of hydrocarbons.
To drill an oil or gas well, exploration and production companies use drilling rigs. There are some differences between these based on whether they are used for onshore or offshore drilling, but both onshore and offshore rigs share their main components: a drill bit, a drill string to which the bit is attached, and a rotary table that rotates the drill string and the bit.
Besides the drill string and the bit, drilling equipment also typically includes blowout preventers, drill pipes, mud tanks and pumps, a centrifuge, and a set of devices that separate the gas from the oil and the sand and water from the hydrocarbons.
Some components of drilling rigs vary depending on location—offshore or onshore—and on the type of drilling to be performed. Regardless of the type, however, all rigs share several basic components.
- Drawworks:A set of systems attached to the rig to lift and install the drill string and the drill bit; the swivel, which supports the weight of the string and bit and pressure-seals the opening of the well; and the rotary table and the kelly, which rotate the drill.
- Kelly drive: A shaft with a square or hexagonal shape that is connected to the rotating table via a bowl-on-a-plate-like component called bushing. The kelly is hollow to accommodate the water or drilling mud pumped into the well to cool the drill bit.
- Drill pipes: These pipes are connected to the kelly and lowered into the well. They are the connection between the surface equipment on the rig and the subsurface one, that is, the drill string and the bit. After the well is drilled to the target depth, these are taken out.
- Bottomhole assembly: This is the group term for the drill bit and the metal structure right above it whose purpose is to provide enough force for the bit to break the rock.
- Blowout preventer: The blowout preventer is a system of valves that is installed at the opening of the well to ensure against the spontaneous release of oil and gas, and also to keep the drill pipes and the casing of the well from getting blown out of the well when pressure mounts.
- Drill bit: The drilling bit is usually custom made in accordance with the geological characteristics of the prospect. Bits can be loosely grouped into three types: roller bits, which crush the rock; diamond bits, or PDCs, which grind rather than crush the rock and are more durable and faster in soft rock; and directional bits, which have a steerable motor on top to drill in different directions, mostly offshore, where a single wellbore can host several wells but also in shale rock.
Besides these essential components, a drilling site also features a power source—commonly a diesel generator—as well as a mud pit for the drilling mud, a pump to get the mud into the well and then out of it, as well as a centrifuge to separate solids from liquids during the drilling process.
This is the case across oil rigs. However, there is a marked difference between onshore and offshore drilling when it comes to types of rigs. For onshore sites, most rigs look alike. Offshore, it all depends on the depth to be drilled.
Fixed platforms: Fixed platforms get their name from the steel or concrete legs that attach them to the seafloor. These rigs are used in shallow waters of up to 1,700 feet, or 530 meters.
Jackup rigs: These platforms have legs like fixed rigs, but these legs can be raised to move the platform from one place to another and then lowered to attach it again to the seafloor. A subtype of fixed platforms, jackup rigs are mostly used in shallow waters as well.
Compliant towers: These are similar to fixed platforms but with a narrower tower (the offshore equivalent of the derrick) so the platform can move sideways with the wind and the waves. This greater flexibility makes them suitable for greater depths than fixed platforms of up to 3,000 feet or about 900 meters.
Semi-submersible platforms: Semi-subs are floating structures standing on pontoon-like legs that are submerged in the water. They are the platform of choice for drilling locations with harsh weather conditions, and they can be used in both shallow and deep waters with depths of up to 10,000 feet, or 3,000 meters.
Based on the type of anchoring used, semi-subs can be: tension-leg and sea star platforms, which are both connected to the seafloor with flexible steel legs; and spar platforms, which float on the water on top of a hollow cylindrical hull that keeps the platform in place.
FPSOs: Floating production, storage, and offloading systems are the most versatile type of offshore drilling platforms. They can operate in shallow or medium-depth waters, like semi-submersibles, or go into ultradeep waters like a drillship. However, because they combine production with storage and offloading, they are most often used in medium-depth waters of up to 6,000 feet, or 1,800 meters, where this combination makes the most economic sense.
Drillships: Drillships are used for drilling in deep waters where semi-subs cannot operate. To stay in place, the drillship uses various kinds of anchoring. Anchoring types include multiple anchors and dynamic positioning: a system of propellers and thrusters that keep a vessel in place automatically through a computer-controlled program.
Before going into the stages of the well-drilling process, here is a quick overview of the types of wells that oil and gas exploration and production companies drill. They distinguish between:
Wildcat well: The very first well drilled on a new prospect—one that has been clearly defined in terms of geology as an oil and gas prospect, but which lies outside of any known oil and gas fields.
Appraisal well: A well drilled to determine the extent and size of a discovery made through seismic imaging; in other words, to assess the characteristics of a proven hydrocarbon deposit.
Production well: A well drilled in the sweet spots of a field with proven commercial reserves of oil and/or gas to extract the hydrocarbons for commercial purposes.
Onshore, the land plot on which the well will be drilled needs to be leveled so the crew can assemble the derrick, and roads need to be built to bring in all the drilling equipment.
Mud pits and storage pits then need to be dug for any solids separated from the liquid in the drilling process. In some jurisdictions, mud pits are banned and used mud is instead collected in metal reservoirs that need to be put together during the preparation stage.
Finally, the crew will build what in the industry is called a cellar: the place where the well will be drilled and where all the drilling machinery will be assembled.
Offshore, none of this applies. There, everything happens on and from the platform, where the drilling equipment is delivered by air or by boat, and installed on the platform itself from where the drill string is lowered into the water and into the seabed.
This is when the actual drilling begins. It starts with the drilling of a conductor hole: a shallow hole of between 100 and 200 feet, or 30-40 meters that is cemented in place or lined with so-called conductor casing (steel piping). The purpose of the conductor hole is to prevent the top of the wellbore from collapsing in on itself.
Once the conductor hole is in place and cased, the drilling proper begins. The derrick is assembled over the wellbore and the drilling equipment is assembled.
Drilling proper takes place in stages. The first stage of drilling proper is drilling a hole of some 300-500 feet, or 100-250 meters, whose aim is to first seal off the well from the surface aquifers in the area and stabilize the top of the wellbore.
This is done by installing well casing—steel pipes—in the wellbore and then pouring cement into them via the drill string. Once the cement reaches the bottom of the hole, it is pushed back up along the sides of the casing, fixing the wellbore in place and insulating it from the aquifers. This casing-and-cementing process is repeated for every stage of the drilling process.
This first proper drilling stage is the most important one because it is the stage where the blowout preventer is installed on the casing pipe to prevent a blowout from the well. Once this is done and the BOP is activated, drilling continues down to the desired depth. In shale oil drilling and in shale gas drilling, there is an additional stage of lateral—also called directional or horizontal—drilling once the maximum desired depth is achieved.
During the drilling process, water—or more commonly, drilling mud—is injected into the wellbore to cool the drill bit and also to flush out the rock cuttings that the drill bit produces and that, if they accumulate around it, would force it to stop drilling. These cuttings are collected in pits or reservoirs on the surface.
Once the last section of the well has been drilled, cased, and cemented, the well is completed and ready to start producing. The typical conventional well remains open-hole, meaning the end of the wellbore remains open into the reservoir of hydrocarbons and they flow straights up.
Unconventional wells, on the other hand, need to be perforated to allow the hydrocarbons to begin flowing in. This is called cased-hole completion and involves one additional stage in the drilling process, during which a perforation gun is inserted into the wellbore to perforate the casing, so the hydraulic fracturing liquid can be pumped through the holes and fracture the surrounding shale rock to release the hydrocarbons.
Drilling an oil well takes several months and continues around the clock. It is a complex, labor-intensive process, often performed in challenging environments such as deep waters or even the Arctic. Yet the whole oil and gas industry depends on this process, as does a lot of the world’s energy supply.
Service rigs in Canada, and the crews that operate them, are sought after around the globe. CAOEC Service Rig members have operated their equipment from Australia to Russia and everywhere in between. The Western Canadian Sedimentary Basin (WCSB) is one of the most challenging basins to produce hydrocarbons, and the rigs and people developed working in the WCSB have experience that is second to none.
Service rigs are much smaller than drilling rigs and they are fully mobile. Where a drilling rig requires trucks to move its various pieces, a service rig"s equiment is on wheels, and can be driven from location to location. Mobility is required because unlike drilling rigs that, once situated, can spend months in the same location, service rigs will move often (sometimes daily) to new jobs on different well sites.
Combined, CAOEC Service Members operate over 900 rigs in Canada. The demand for service rigs is generally different than for drilling rigs, and is not as directly impacted by the price of oil or natural gas. Work on existing wells can be more economical when commodity prices are lower because operating costs are not as high, and returns are often more predictable. This means service rigs may still be busy when producers aren"t otherwise looking to drill new wells.
From turning exploratory wells into producing wells, to shutting wells in (temporarily halting well production), to repairing wells as required, to abandoning wells (permanently and safely closing the well) service rigs are used to perform a variety of different services and will often return to the same well site many times. The service rig unit carries the mast structure (otherwise known as the derrick) and the rig floor. When a rig is working downhole, the unit is secured with its derrick sitting over top of the well bore.
Like drilling rigs, service rigs also come in different sizes. A typical rig is close to 20 meters long with the board. With the board and derrick laid over, it is just over four meters high. The laid-over derrick can hang out anywhere from one to eight meters beyond the cab. When loaded up and ready to move a typical rig can weigh up to 50,000 kilograms and is close to 20 meters long (with the laid-over derrick extending anywhere from 1 to 8 meters beyond the cab) and 4 meters high.
Additionally, service rigs work on both oil and natural gas wells, and must adjust their procedures accordingly. These must rigs keep pace with all of the market driven changes in activity, and as such have made technological adjustments along the way. Service rigs, however, don"t vary as greatly as drilling rigs, and many of the anciliary well services are handled by purpose-built, specialty equipment such as coil tubing or fracking units.
Independent producers and operators ramping up shale exploration and development programs are pushing the limits of conventional drilling equipment. Whether they are drilling multiple long-lateral horizontal wells from single pads, testing new bits and mud motors to boost penetration rates, or deploying next-generation rig floor and automation systems to slash “spud to sales” times, independents and their service company partners continue to find ways to improve resource play economics and crack the unconventional drilling frontier wide open.
Goodrich Petroleum is a case in point. Over the past two years, the company has transitioned from vertical Cotton Valley wells to horizontal wells in the Cotton Valley and the underlying Haynesville Shale. To unlock the shale’s vast potential, the company worked with its partners and service providers to discover the right casing points and to choose bottom hole assemblies that could build at sufficient rates to maximize lateral lengths, reports Clarke Denney, the company’s vice president of drilling. He notes that in the Haynesville Shale, Goodrich is utilizing robust directional equipment and mud cooling units to drill laterals at vertical depths of 15,000 feet, where circulating temperatures can reach upward of 340 degrees Fahrenheit.
The company’s efforts have paid off. By shifting focus from vertical Cotton Valley wells to the Haynesville, Goodrich reduced its overall proved developed finding and development costs from $3.21 an Mcf of gas equivalent to $2.38 an Mcfe from 2009 to 2010.
With oil prices trading much higher than natural gas on a Btu equivalent basis, Goodrich also is targeting the oil window of the Eagle Ford Shale. In South Texas, the company is drilling wells with vertical depths between 6,500 and 8,500 feet and lateral lengths from 4,500 to 6,000 feet. Although these wells take skill, time, and money to plan and construct, company officials say they believe they can achieve 50 plus percent returns on investment.
Drilling wells in either play requires rigs with the right equipment, says Denney. He says top drives are important because they allow pumping and rotating the drill string while coming out of the hole, which is necessary at times for hole cleaning. This reduces drag and the chance of getting stuck. Top drives also maximize directional drilling performance.
Drawworks that can deliver at least 1,500 horsepower are also key, Denney adds. “We believe in high horsepower,” he stresses. “A 1,500-horsepower rig carries a premium over a 1,000-horsepower rig, but it speeds trips and puts less strain on the equipment. We get our money’s worth.”
Just as important as the drawworks and top drive is having powerful mud pumps on the rig, Denney says. “In the Eagle Ford, we would prefer to have at least 1,600-horsepower pumps, especially when drilling long laterals,” he relates. “That horsepower is needed for mud hydraulics to keep the hole clean, and to drive the downhole motor and other equipment. We have achieved up to 6,000-foot laterals to date, and we are targeting 9,000-foot long laterals in the near future.”
In many cases, it makes sense for the rig to have the ability to skid, Denney says. He explains that drilling multiple horizontal well bores on one pad reduces construction costs and rig transit times. “In the Eagle Ford, if we can skid, our drilling costs can be reduced as much as $500,000 a well,” he says.
Goodrich Petroleum is far from the only company that needs “high-spec” rigs with powerful top drives, hoisting systems and pumps. According to industry sources, rigs with larger (+1,000) horsepower ratings account for an estimated 60 percent of the active rig fleet. Moreover, rigs with at least 1,000 horsepower account for nine of every 10 rigs that are under construction or planned for the near future.
With its operational focus transitioning from the Cotton Valley trend to the Haynesville Shale, and more recently to the Eagle Ford Shale, Goodrich Petroleum is achieving consistent production and reserve growth through horizontal drilling with high-spec land rigs and advanced downhole tools. Even during the economic recession of 2009, the company increased average net daily production 24 percent and proved reserves 5 percent. Over the past four years, it has more than doubled its daily production while expanding its reserves 30 percent.
Trent Latshaw, the founder and head of Latshaw Drilling in Tulsa, can verify that the demand for 1,000-2,000 horsepower rigs is high. He says the company’s fleet, which includes 15 rigs within that range, has 100 percent utilization. In fact, Latshaw reports that the only unused rig his company has on the books is a new, 1,700-horsepower diesel electric that is still under construction.
Many of today’s high-spec rigs have closed-loop mud systems, Latshaw notes. “Closed-loop mud systems do away with the need for a reserve pit,” he says. “The systems also processes drilling fluid more efficiently. They are able to take more solids from the drilling fluid, which enables more fluid to be reused and makes the solids dryer and easier to dispose of. That becomes very important when dealing with oil-based mud, which often is used in horizontal wells.”
Latshaw encourages operators to consider using high-horsepower rigs when the class they want is difficult to obtain. “We consider our 2,000-horsepower rig to be identical to our 1,500-horsepower rigs, except for the drawworks size and the mast/substructure capacity,” he says. “The 2,000-horsepower rigs have the same footprint and move as fast as the 1,500-horsepower units, and for all practical purposes, the day rates are the same.”
He also says diesel-electric SCR rigs are comparable to AC rigs. “They have the same top drives, the same mud pumps, the same mud systems, the same engines, and the same blowout preventers,” he reports. “From the customers’ perspective, they drill wells as fast as AC rigs.”
In reference to safety, Latshaw says people matter more than technology. “You can try to design a piece of equipment that is accident proof, but safety comes down to the people on the rig floor and what their mindsets are,” he insists. “We are putting more money into training, beefing up our safety department, and having more safety coaches go around the rigs to work with the hands.”
He points out that many rigs, including several of Latshaw Drilling’s units, use automated iron roughnecks to improve safety. “Those are expensive, high-maintenance pieces of equipment,” he says. “We decided to take some of them off our rigs, then track closely to see if we had more finger and hand accidents on the rigs using manual tongs and a drill pipe spinner versus the rigs that had iron roughnecks. We have not seen a difference.”
For Joe Hudson, the president of Nabors Drilling USA, the future looks bright. “We have at least 103 AC rigs deployed at this point,” he reports. “We are in the process of building 25 more, and we always are looking for opportunities to expand further, be it in the Bakken, the Mid-Continent, West Texas, the Eagle Ford, or the Marcellus.”
Hudson says the new rigs include larger pumps, AC top drives, and tubular handling tools such as automatic catwalks and floor wrenches. “With the automatic catwalk, there is no need for a rig hand to pick pipe off the catwalks, pull it up with a hoist, and drag it to the rig floor,” he says. “Instead, the catwalk picks up pipe and elevates it to the rig floor. No one is touching the pipe or rolling pipe onto the catwalk, which keeps people away from tubulars, reducing the risk of pinch-point injuries.”
The floor wrench also improves safety, Hudson says. “Normally, a roughneck would make up pipe with manual tongs,” he notes. “The floor wrench engages the pipe and makes it up with an automatic tool, which keeps his hands safe. It also increases pipe longevity by reducing damage from the manual tongs.”
Hudson says statistics and feedback show the new equipment reduces accidents. “There is an efficiency gain as well,” he adds. “With this equipment, we have improved control and improved well hydraulics, which results in faster well times.”
The rigs also employ advanced software. “With conventional rigs, the driller would drill ahead with a hand on the brake handle. He had only basic drilling information available to him, and his skill and his experience with the area dictated his ability to drill the well,” Hudson recalls. “Today, the software associated with smart drilling systems allows him to drill the well with a better understanding of the factors that influence drilling performance, such as delta P, hydraulic horsepower, weight on bit and rate of penetration. That translates to a faster rate of penetration.”
To ensure that its employees work as safely and efficiently as possible, Nabors has fully functional training rigs in Williston, N.D., Casper, Wy., and Tyler, Tx., where it trains personnel with no previous experience, Hudson reports. He adds that the company carefully defines the training and competency individuals need to be promoted.
The newest generation of high-spec land rigs purpose-built for horizontal drilling in unconventional resource plays features integrated subsystems to automate key processes such as pipe handling. Automated catwalks and floor wrenches not only increase operating efficiency, but also improve rig floor safety and extend pipe longevity by reducing handling damage.
Nabors’ focus on training and its preference for promoting from within help it maintain a skilled workforce, Hudson indicates. “When the market is expanding, we are able to identify promising, trained personnel within the company, give them a career path, and move them through the system. That helps with retention,” he explains.
When downturns do occur, Nabors tries to keep competent people and trainers on staff, Hudson says. By doing so during the last economic downturn, he says the company managed to go from 92 rigs in fall 2009 to 190 rigs today without compromising its personnel or safety standards.
Regardless of the market condition, Hudson says it is vital to design rigs for specific areas. “Every area is unique,” he says. “Carrying the top drive in the mast is a great way to reduce the number of loads needed, but in areas where road weights are critical, other approaches have to be adopted.”
To illustrate regional developments, Hudson points to Nabors’ B-series rigs, which were designed to accommodate pad drilling in the Bakken Shale. “We built a box-on-box substructure because we can close in that substructure, which makes it easier to winterize,” Hudson says. “Also, the way we can rotate the substructure lets the company conduct completion and production-related operations on one well while we are drilling another on the same location.”
In the Rocky Mountains, mobility is vital, says Patrick Hladky, a principal and contract manager for Rockies-focused Cyclone Drilling. “It is important to optimize mobility because we cover such a large area,” he says.
Dealing with cold weather is also important, he observes. “We protect the rig floor from wind by putting the dog house and wind walls around it, then put heaters on the floor,” he says.
Like other contractors, Cyclone is expanding its fleet. “We built five rigs in 2010 and we are scheduled to build four more in 2011,” Hladky details. “They all have 1,600-horsepower pumps, with 270- and 500-ton AC top drives.”
Hladky says Cyclone tries to keep the rigs’ designs simple. “We engineer all the rigs similarly,” he adds. “Even if they are different sizes or different applications, the basics are all the same. That lets employees move from rig to rig efficiently and safely.”
The company also tries to put equipment in convenient places. “For example, rather than putting the oil storage tanks in a separate building, we put them with the engines,” Hladky says. “That is where our hands will use them.”
In the Bakken Shale, Continental Resources is drilling four-well pads. By drilling and casing all four surface holes, then all four intermediate holes and finally all four laterals, the company reduces the number of times it needs to change the mud type and drill pipe. Continental says this process reduces drilling costs as much as 10 percent.
Like the other drilling contractors, Hladky stresses the importance of good people. “A high-spec rig is nothing without good people,” he declares. “We are drilling with mechanical rigs built in the 1980s and 1990s with good people right next to and as efficiently as high-spec rigs.
“We have a young workforce, especially in the Williston Basin, which has grown so fast a lot of the people are new to their jobs,” Hladky observes. “That means we need to do more training. We have put night supervisors on location so the hands can get help and training at night.”
Cyclone Drilling also trains hands on site through a mobile training center, Hladky reports. He adds that the company hired Afterburner, a leadership consultant, to help its supervisors and managers promote safety and efficiency. “We are seeing results from that already,” he reports, noting that Afterburner emphasizes focusing leaders on teaching, rather than policing.
The combination of experience and training has paid off. “We already have seen efficiency gains from when we were first ramping up a year ago,” Hladky says. “The longer the cycle becomes, the more gains we will see.”
Pad drilling has a long and successful history in the Rockies and has spread to basins across the United States, Hladky points out. “It creates efficiencies for drilling times and costs, as well as environmental benefits. The pad is only disturbing the land in one area, even though it allows several wells to be drilled, completed and produced from that one surface site.”
Cyclone skids its rigs with hydraulic feet rather than rails because rigs can get slightly off target each time they move from one well to the next. “If you are on a rail system, the error is difficult to deal with. A walking rig can move in any direction needed to position exactly over the well bore,” he says.
On pads with several gas wells, Hladky says the operator can do simultaneous operations. “As we are drilling one well, he can set up his frac crews on a different location and pipe fluids to the pad to complete a well or put wells on production. That lets the operator get a return on the investment without waiting for the entire pad to be completed.”
On other pads, Hladky says Cyclone advocates batch drilling. “In this case, we drill all of the well’s surface holes as a batch, then drill all of the intermediate sections, and conclude with drilling all the laterals,” he says. “Instead of swapping mud systems several times for each well, we can use the same mud system and tools over and over.”
In addition to reducing the amount of time directional drilling companies need to be on site, that approach makes life easier for the crew. “They are not changing hole sizes or changing well parameters,” Hladky explains. “The repetition creates efficiencies. More than likely, your last well will be faster than your first one.
Continental Resources has used batch drilling to great effect in the Bakken, reports Glenn Cox, the company’s northern drilling manager. He says the company is using four-well pads, with two wells on each pad targeting the Middle Bakken interval and two targeting the Three Forks formation.
“We started looking at these pads primarily from a surface usage viewpoint,” Cox says. “Since the terrain in North Dakota can be difficult, we wanted to reduce the number of pads, handling facilities, power lines, and pipelines we had to build. As we dug into the process, we began to ask if we would save any money beyond the cost of building the location and moving the rigs. The batch process provided the cost savings that gave us the impetus to keep working on the project.”
To use pad drilling to full effect, Continental had to overcome a hurdle: North Dakota’s setback laws. “Setbacks from the lease line were normally 500 feet,” Cox recalls. “When we drill a well, the curve radius is 450 feet. The drilling location is roughly 150-200 feet from the section line, so once we drill the curve and set the casing, we have achieved the required setback.”
The problem was that the 500-foot setback made it difficult to drill into the adjacent section. “To achieve the setback there, I would have needed to drill 650-700 feet. That means we would have had to drill the curve down, trip out to get a different motor, and go back in to finish the last 200-300 feet before setting casing,” he details.
As of mid-March, Continental had drilled seven pads. The batch drilling process and pad construction savings reduce the cost of drilling each well as much as 10 percent, enough to save the company $2.5 million for each pad, Cox says. He adds that the process reduces surface impacts by as much as 75 percent.
To explain the process’s economic and environmental benefits to investors, Continental dubbed it ECO-Pad® and produced a video, which is now available on its website. “It’s been amazing how many people have watched the video and asked to show it to others,” says Brian Engel, Continental’s vice president of public affairs. “The walking rig is something almost no one has seen before, especially in the investor community.”
As drilling contractors build their fleets and train employees, equipment manufacturers are coming up with better ways to design and manufacture components. These include downhole motor manufacturers. “We are dedicating significant resources toward boosting overall motor performance, with specific focus on increased power and equipment reliability,” says Mpact Downhole Motors Vice President David Stuart.
From the field to the office, equipment manufacturers are working with operators and service companies to improve drilling efficiency. For example, they are developing mud motors that can support higher rates of penetration without sacrificing reliability, as well as solids control equipment that offers greater efficiency and flexibility.
To maximize reliability, Stuart says manufacturers are designing downhole motors that can operate under increasingly higher loads. In addition, they must ensure motors are designed to be compatible with ever-changing drilling conditions. “Drilling motors have to be designed and calibrated for each specific application to compensate for changes in temperature and other downhole conditions, which will cause the components to expand and contract during drilling,” Stuart remarks.
Premium elastomers are playing a key role in manufacturers’ efforts to improve reliability, Stuart says, explaining that the new-age materials also provide higher differential pressure and torque.
Stronger motor transmissions and bearing assemblies also are on the industry’s drawing boards, Stuart says. “We have worked with key suppliers to develop new thrust bearing designs to increase load capacity,” he says. “The higher capacity improves reliability and offers increased weight-on-bit, which enables higher penetration rates.”
Even with the best motors, Stuart advises operators to stay within the motors’ optimum operating parameters. “The drilling motor is similar to an engine in a car,” Stuart says. “You can run it at the red line on the tachometer and go really, really fast for a short time, but if you run that hard for a long time, the engine is going to have problems.”
The ideal operating range varies with motor sizes and configurations, Stuart says. “Experience goes a long way in determining the right range, and it comes not only from the drilling motor provider, but also from the service companies and operators. Collaboration among the three is important for efficient drilling operations,” he advises.
The combination of technology and experience has paid off, Stuart says. “Our motor run success ratio has improved continuously. It is now above 98 percent,” he reports.
The mean time between failures (MTBF) also has improved, Stuart says. “At our company, the MTBF in 2008 was 3,069 hours,” he recalls. “In 2010, it was 3,509 hours, a 13 percent improvement. We are extremely proud of that, especially given that equipment continues to be pushed harder and harder.”
No matter how hard operators push their equipment, the fundamental goal of fluids handling systems remains the same: keeping the drilling mud in good condition. But with the cost of drilling fluid additives and oil-based mud on the rise, KEM-TRON Technologies President Michael Rai Anderson says it is becoming increasingly beneficial to manage mud through solids control treatment systems. “Fluids handling companies have responded,” Anderson states. “We are finding ways to remove contaminants from the drilling mud while recovering as much usable material as possible.”
Drilling contractors are expanding their fleets to accommodate growing demand for high-horsepower land rigs equipped with powerful mud pumps, heavy-duty drawworks, closed-loop mud systems, automated rig floor equipment and ‘smart’ data management systems. As with this 1,500-horsepower electric rig, these new high-spec units often are fitted with top drives to rotate the drill string to optimize drilling efficiency and reduce the chance of pipe sticking while coming out of long horizontal laterals.
Anderson says several developments will help with that effort, including a new shaker that enables the operator to vary the gravitational force imparted between three and eight gravities. “Being able to fine-tune the shaker to the solids load will help operators get a better cut and reduce screen consumption,” Anderson says. “High G-forces can be used during top-hole drilling, when solids loading is high, and lower G-forces can be used when solids loading drops. This improves residence time and ultimately solids cut.”
To maximize performance and cost effectiveness, the shaker uses a passive-vibrator technology, Anderson says. “The system uses gears instead of rotating unbalanced weights,” he outlines. “The passive vibrator assembly reduces the complexity of electrical systems needed to create the variable frequency, enhancing system control and maintenance.”
Vertical cutting dryer technology also is improving, Anderson indicates. “We are working on new chemical injection techniques to break the surface tension between oil-based drilling fluids and the cuttings. This lowers the energy required to separate the fluid from the cuttings.”
A typical cuttings dryer can reduce the amount of drilling fluid on the cuttings from 15 percent to 5 percent, Anderson says. “With chemical injection enhancement, we may be able to bring that down to 1 percent,” he reports.
According to Anderson, the new chemical injection techniques are part of a growing trend: When it comes to environmental issues, oil and gas companies are going beyond regulatory requirements. Anderson goes on to state, “This means that the technology is evolving and new products will enter the market, making solids control and waste management more efficient and cost effective.”
To help centrifuges separate water and cuttings, operators often add coagulants and flocculants to the drilling fluid before it reaches the centrifuge, Anderson notes. Ideally, the coagulant neutralizes the suspended solids’ electrical charge. Once that happens, the flocculants’ electrical charge will attract the solids and bind them, which will keep them from mixing with the water in the centrifuge. This makes the centrifuge more effective, Anderson explains.
To work well, the coagulants and flocculants need to be conditioned, or “made down.” Conditioning involves mixing a concentrated form of the polymers with water, then waiting for them to uncoil, Anderson says. If this process is done poorly, he says the coagulants and flocculants will go to waste and the centrifuge will fail to separate the water and suspended solids to the degree intended.
“Getting hydration right can be tricky,” Anderson says. “The coagulants and flocculants typically used to dewater drilling fluid have long, fragile chains, so they are sensitive to high mechanical shear forces and temperatures. Low pressure is also a concern; it increases residence times.”
Because hydration is the most important aspect of maximizing polymer effectiveness, Anderson says his company has developed an affordable, modular chemical injection system that uses automation to closely control hydration. “The system controls the polymer’s flow rate, water pressure, polymer mixing, polymer residence time within the manifold, and the temperature at which the polymer is being conditioned,” Anderson reports. He adds that the retrofits needed to install the system on an existing centrifuge are minimal.
In addition to expanding the capabilities of existing technologies, Anderson says manufacturers and end-users are scrutinizing almost every piece of solids control equipment on a quest for stronger, lighter and smaller equipment that can perform heavyweight tasks. This requires more than product engineering, it requires value engineering. “In value engineering, companies critically examine the equipment configuration, operating philosophy, raw material selection and fabrication practices,” Anderson says.
That approach is being applied to centrifuges, Anderson reports. “About 50 percent of a centrifuge’s cost is in the rotating assembly,” he observes. “We are looking at ways to lower that cost and improve the quality by using different materials and improving the geometry of the parts to reduce the need for time-consuming and expensive machining.”
Improved designs likely will reduce large bowl centrifuge costs 10-15 percent, enough to temporarily offset the ever-increasing cost of raw materials such as stainless steel, Anderson says. He adds that streamlined supply chains will reduce costs and improve delivery times and quality.
While they work to reduce costs, Anderson says manufacturers are finding ways to enhance equipment operability. “We are improving the centrifuge’s programming and interface, and adding onboard sensors so the operator can obtain a clear picture what is happening within the centrifuge,” he illustrates.
New centrifuges can include sensors for temperature monitoring, flow sensors, specific gravity sensors, amperage loading on the motors, temperature sensors on the bearings, level sensors within the centrifuge, and wear sensors on the scroll’s flight, Anderson details. These sensors will help the user automate the centrifuge’s operation and facilitate global performance monitoring through Web-based applications, he concludes.
Latshaw Drilling’s Trent Latshaw says improvements in rig designs, downhole motors, and fluids handling equipment are only a small part of a larger effort to improve drilling efficiency. “Polychrystalline diamond compact bits, measurement-while-drilling tools and rotary steerables will continue to be major drivers,” he predicts.
“The world has changed with respect to domestic exploration, drilling, and production,” he says. “Unconventional development has expanded the United States’ oil and gas reserves dramatically, but it also has increased the complexity of the technology needed to drill, log, and complete a well.
“Total well drilling, completion and construction costs range from $7 million to $8 million in many of the established shale plays, particularly for wells with ultralong laterals.” he says. “In the Granite Wash, drilling and completing a well can carry a price tag exceeding $8 million. Given these costs, it is imperative for operators and contractors to be aware of the latest technology.”
Based on our extensive experience in the design of land rigs and special vehicles, Sovonex™ truck-mounted drilling rigs are a prime example of advanced engineering.
When drilling on impassable terrain or in remote areas, our truck-mounted drilling rigs’ excellent off-road capability and mobility can make the difference between a drilling operation being commercially feasible or not.
With our extensive experience in the manufacturing of skid-mounted rigs and oilfield vehicles, we are able to design each Sovonex™ mobile rig to individual customer requirements.
Your mobile drilling rig can be 100% made in China, or you can choose rig components from distinguished international suppliers as you like. By default, the following rig components are imported:Main diesel engines: Caterpillar
A key advantage of our truck-mounted rigs is their uniquely constructed chassis. Designed for extreme stability and with a small turn cycle, they give the rigs the power and mobility required for driving on impassable terrains.
Customers can choose between different types of suspensions, including single wheel independent suspension. A mobile rig with independent suspension is especially advantageous when driving in inaccessible mountain regions.
At our production facility in China we manufacture the complete range truck-mounted and trailer mounted drilling rigs capable of drilling wells from 1000m to 4000m. Below you will find a detailed description for each of these rigs.
This 4000m truck-mounted rig with a power of 1000 hp is the most powerful among our mobile rig and often employed in geothermal drilling operations in remote mountain regions.
The specially designed chassis is optionally available with independent suspension on every wheel, giving it superior driving characteristics on rough and extremely muddy terrain.Drilling depth (4-1/2” DP): 4,000 m (13,000 ft)
We do manufacture both truck-mounted and trailer-mounted drilling rigs. While truck-mounted rigs are more compact and easier to handle in rough terrain, the truck of a trailer-mounted rig can be used for other purposes during drilling operations.
The 4000 m mobile rig can optionally be equipped with a top drive system. We provide repair and maintenance services for all major top drive manufacturers like Varco, Canrig, Tesco, BPM, MH, and Bomco
With every drilling rig we send technical staff to the drill site to provide first hand technical support. The engineer responsible for the design of the rig is always part of the service crew.
For your convenience, here is a summary of the benefits of our truck-mounted drilling rigs we consider the most important:Production quality standard API Q1 and ISO 9001
Aug 26 (Reuters) - North American onshore rig contractors are spending millions of dollars to add costly “walking” rigs to their fleet, a move that may seem counterintuitive at a time when the slump in crude prices shows no signs of abating.
Such rigs “walk” from wellbore to wellbore, unlike a regular rig that has to be taken apart and reassembled for each move, and save shale producers time and money - as much as 30 percent of the cost to drill a well.
Even though the returns on these investments will not be immediate, rig contractors such as Patterson-UTI Energy Inc and Pioneer Energy Services are pandering to the demand for these rigs.
Demand for rigs have taken a walloping, as oil producers have slammed the brakes on drilling new wells to cope with a 28 percent decline in U.S. crude prices this year.
“As activity starts picking up again, the majority of requests from operators, I think, will be for pad-oriented rigs,” said Pioneer Energy CEO Stacy Locke, referring to the popular practice of drilling several wells in one location.
This promise of higher demand and better rates has led