TECHNOLOGY AT WORK

Five new techniques improve production / drilling operations

ncluding a U.S. DOE-supported program zeroing in on the efficiency of sucker rod pumping wells, three downhole systems for: fluid lifting problems, well / reservoir testing, and maintenance / repair, plus a better way to handle drilling mud, the following review of five field-tested technologies gives valuable options for several persistent operating problems.

These new techniques summarize concepts and case histories of:

1. How Oxy USA improved five field wells for a pumping unit "Motor Challenge" project;
2. Using capillary tubing to inject chemicals to alleviate unwanted downhole fluid / solids buildups;
3. A pressure-activated sealant for downhole leaks;
4. Application of a new, programmable downhole valve for well / reservoir testing; and
5. Mud tank mixers that can be adapted to the shape of any vessel.

Upgrading the performance of oil well pumping units

OXY USA, a subsidiary of Occidental Petroleum Corp., provided five oil wells at its Bemis oil field in Ellis County, Kansas, for an experimental program called the Motor Challenge Showcase Demonstration, aimed at increasing efficiency and performance of beam-type oil pumping units. By making electrical and mechanical modifications to these wells, OXY was able to reduce operating costs and identify specific modifications that can improve efficiencies of its other wells.

The mechanical and electrical modifications reduced annual energy consumption by more than 12 %, or 54,312 kWh, resulting in $2,227 of annual energy savings. Another $3,135 in annual savings was realized through reduced electricity demand charges, resulting in a total $5,362 annual savings from the project. The simple paybacks for each of the wells ranged from 2.6 to 16.1 months, with a total project simple payback of 6.5 months. The total savings in both energy and demand charges amounted to about $0.77 per barrel oil pumped.

Project overview. With the price of oil declining and their oil wells maturing, companies in Kansas were (are) faced with energy costs for pumping oil which at times exceed 50% of the produced crude price. As a result, many independents are forced to shut down marginally operating wells, leading to significant revenue reductions for the state’s electric utilities. As a result, the Kansas Corporation Commission (KCC), the state’s utility regulatory body, funded a study seeking to identify specific technologies to improve pumping unit efficiency and reduce costs. Some additional funding was provided by the U.S. Department of Energy (DOE).

The Center for Energy Studies at Wichita State University (WSU) and DynCorp Corp. analyzed Kansas’ entire oil industry and identified promising technical modifications. OXY then instituted an experimental program on five of its beam-type pumping units to implement and measure effects of these modifications.

This Motor Challenge Showcase Demonstration project required the cooperation and teamwork of four organizations: OXY hosted the project; DynCorp was responsible for data analysis; Midwest Energy, Inc. (the local electric utility) contributed electrical metering, personnel and additional funding; and WSU provided technical consultation during the project and co-authored a report with DynCorp. This report, An investigation of methods for reducing the cost of pumping oil in Kansas, comprises a broad study of overall oil production in the state, including recommendations on reducing pumping costs.

Systems approach, implementation. Each pumping unit analyzed includes an electric motor, belt drive, gear reducer, crank arm with counterweight, walking beam, horsehead, sucker rod and underground pump. The wells, which operate at a fixed speed 24 hr/day, 365 days per year, are usually only shut down for maintenance or operational problems. The only controls on these systems are shut-off valves in the discharge line from the wellhead.

Analysis of the system showed that the total average demand (average apparent power) and annual energy consumption of the five wells were 765,624 kVA and 445,884 kWh, respectively, for a total annual operating cost of $28,165. To identify modifications that could improve operational efficiencies, the Demonstration team ran a series of tests on the five oil wells.

OXY performed dynamometer tests on all five wells and measured pump speed, fluid level, stroke length at both surface and pump, and pump size. Using totalizing flow meters, the company kept daily logs of total flow rate from each well. In addition, Midwest took short-term electrical power measurements using power analyzers / loggers, and long-term electrical power measurements using utility power meters. Finally, OXY supplied oil fraction and pumping speed statistics. Several months’ data established the motor systems’ capabilities with respect to well requirements.

Taking a systems approach, the team analyzed and modified both electrical and mechanical components of the well pumps. Electrical modifications included: checking the service conductor sizing and losses, replacing one well’s motor with a smaller-sized unit, and adding capacitors to correct the power factor. Mechanical modifications included: inspecting and lubricating gearboxes / bearings and replacing worn parts, dynamic balancing of the unit, inspecting / tightening / replacing belts, inspecting / adjusting the packing head seal, and adjusting stroke length. After analyzing the five wells, the team made the following electrical and mechanical modifications:

Well B4: Lubricated gearbox, inspected bearings, balanced beam pump, installed / tensioned new matched set drive belts, adjusted pump stroke, greased and serviced beam pumping unit and installed secondary capacitors.

Well B15: Replaced oversized 30-hp, 480 V.3 phase NEMA D motor with similar 10-hp unit, reduced pumping speed to 8.75 spm from 10.6 spm, greased / serviced pump unit and installed secondary capacitors.

Well B19: Repaired high-resistance connection in one phase of the motor control center and installed secondary capacitors.

Well B20: Installed secondary capacitors.

Well B21: Balanced pump, installed / tensioned new drive belts, adjusted pump stroke, greased / serviced unit and inspected bearings.

Results.  Because the operating point of each well changed during the evaluation period, results obtained were normalized to provide a comparison between cases in which well output was the same. In addition, one common observation made throughout this project was that all five of these mature wells exhibited a steady deterioration in well performance over time. Since Wells B19 and B20 did not undergo any physical modifications at the wellhead, they were suitable for quantifying the magnitude of this long-term decrease in performance. Thus, by factoring out the effect of well deterioration over time, the team was better able to gauge impact of mechanical / electrical modifications.

Based on several months’ data taken after the optimization measures were implemented, the mechanical modifications yielded varying degrees of improvement from well to well. The greatest decrease in energy consumption occurred in Well B15, in which installation of a new, smaller motor and other mechanical modifications resulted in a 21% decrease in electricity usage. In all cases, addition of secondary capacitors significantly improved the power factor, increasing it to 0.76 from an average 0.58. This markedly decreased demand and represented more than half of the cost savings.

Using the adjusted measurements, the five wells showed decreases in energy demand ranging from 24% to 40%. In addition, wells that underwent modifications beyond installation of secondary capacitors realized a drop in energy consumption of 13% to 21%. The project’s total annual cost saving of $5,362 was derived from reduced demand charges, which fell 32%, and reduced energy costs, which fell 12%.

Because the industry considers simple paybacks of 12 to 18 months for small companies and 2 to 3 years for large companies economically viable, this Demonstration project’s simple payback of 6.5 months shows that the well modifications are economically worthwhile. In addition, the wells studied were in generally good condition. Since OXY has a program to perform routine maintenance, it is estimated that the wells studied are more efficient than the "average" well — a significant part of this difference being attributable to infrequent maintenance and oversized motors. Thus, implementation of a program of this nature to the general oil well population can be expected to yield much greater savings than those reported here.

For mature wells, where about one percent of the fluid pumped is oil and the rest is brackish water, this represented a savings of 8 kWh (about $0.32) per barrel oil pumped. The total savings in both energy and demand charges amounted to about $0.77 per barrel oil pumped.

In addition to the electrical cost savings, this project also provided OXY with several other benefits. For example, the well analyses helped the operator prevent potential equipment failure by detecting problems before they were serious enough to cause downtime. For example, the high resistance connection in Well B19 was discovered during these tests. Further, the varying energy measurements of specific wells provide data that can be used to examine potential causes of low efficiency in some wells. This information can be helpful in determining if a change in well operation is mandated, or if a well has merely reached the end of its useful life.

Lessons learned.  Implementation of energy efficiency measures in this demonstration project provided several practical lessons that can be applied to future analyses at Bemis oil field and elsewhere. First, using the smallest motor that enables the pump to operate can significantly improve oil well efficiency. Second, total cost savings are a function of both energy saved and reduced demand. The value associated with each is a function of the rate structure of the utility.

In this study, a large part of the savings was due to a reduction in demand charges. For situations in which the power factor penalty is large, additional attempts to correct that factor even closer to 1.0 may be economical. Finally, measuring liquid level in the well, along with power and flow, ensures that the correct elevation level is used when calculating the minimum energy required for pumping. Further analysis using this parameter can help determine if specific pumps are over- or under-pumped.

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Concentric capillary tubing solves common production problems

Kent Snider, President, Downhole Injection Systems, Oklahoma City, Oklahoma

In low-volume natural gas wells, fluid accumulation can occur in the tubing and wellbore when the gas velocity and production rates are insufficient to lift fluids. This increases operating costs. In specific geographic areas, another major problem in oil and gas wells can be salt and / or paraffin buildup. Additional concerns include corrosion / scale buildup and control.

To address these problems, operators now have a new weapon at their disposal. New alloys have led to an innovative twist on coiled tubing technology — concentric coiled tubing (CCT). In turn, CCT has been employed in a downhole continuous injection system, a patent-pending technology developed by Downhole Injection Systems (DIS).

Field data indicate that the DIS system can be a cost-effective solution to costly production problems. The corrosion-resistant coiled tubing used in the system is 1/4-in. OD, .035-in. wall duplex stainless steel 2205 alloy (DSS 2205). The system can be run to depths of 24,000 ft, with an average installation time of 3 hr, from start to finish. It can be pulled and re-run into the same well, or another well, at minimal cost. Installation can be made in a flowing well without interruption, and no workover rig is required, Fig. 1. The system delivers any volume from 1 gal to as much as 16 bbl/day of chemicals directly to the problem source.

Fluid buildup.  One example where fluid buildup can restrict gas production is in the Cotton Valley reservoir of East Texas, which is at a depth of 9,500 to 10,500 ft. There, the DIS system runs its small-diameter coiled tubing into the production string, through the packer and down to the perforated intervals, without interruption.

The coiled tubing allows introduction of a foaming agent to lighten the fluid and carry it out of the well. The chemical is delivered continuously, preventing any further buildup. Significant production increases are observed and sustained over time, with an average economic payout of 45 to 60 days.

Sustained production increases are illustrated for one Cotton Valley well, Fig. 2. Observed production increases for several wells in a group can vary widely. In one instance involving four wells, output increased 28%, 46%, 60% and 676%, respectively.

Salt buildup.  Rapid accumulation of salts and scale in the tubing or casing, at or above the perforations, is another common headache for operators. Production ceases, requiring expensive wireline cutting procedures, as well as deferral of several days’ production. These costly procedures and lower output rates reduce well profitability significantly.

When the downhole injection system is used, a chemical mix is injected downhole, on a 24-hr-a-day basis, to prevent salt / scale buildup. For instance, salt buildup occurs frequently in the Travis Peak formation in Panola County, Texas. Injection of a 2% potassium chloride (KCl) solution with a small amount of surfactant below the perforations has proven effective in keeping salt in solution. Production and pressure data for a typical field well, showing the stabilized output, are shown in Fig. 3.

Paraffin buildup.  In another test case, a well that initially flowed naturally from a depth below 7,000 ft began experiencing paraffin buildup at 3,500 ft, as production declined. As paraffin content reached 20% by volume, the paraffin had to be cut, on average, every 10 days. The well was put on pump, and the downhole injection system was used to inject a paraffin inhibitor at 3,700 ft. Since the system’s installation in May 1997, production has not been interrupted for paraffin cutting.

Bottom line impact. Large and small operators, alike, report that they are reducing costs and increasing production by employing the downhole injection system. During roughly the last two years, more than 200 systems have been installed. Some are now running at 20,000 ft or deeper. In almost all cases, significant production gains have been observed, with immediate output cost-savings and short payouts. Even in the lowest production-gain cases, installation costs have still paid out rapidly.

First used in East Texas, this new technology has been applied throughout the Midcontinent region of the U.S., and it is thought to have potential along the Gulf Coast and in other areas.

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Pressure-activated sealant cures downhole leaks

Pressure leaks in a wellhead, downhole tubulars or other equipment can lead to inoperable subsurface safety valves, casing pressure, environmental pollution, loss of production and, in extreme cases, blowouts. It is the policy of most operating companies and governmental regulators that pressure leaks in surface-controlled, subsurface safety valves (SCSSVs), tubulars or other downhole equipment must be cured or alleviated. Regulations generally prescribe that operational capabilities of SCSSVs be tested, sustained casing pressure reported and wells subject to pressure leaks be shut in until the leak is cured or alleviated.

A major component of the repair cost of such leaks is mobilizing expensive equipment and numerous personnel to the well location. There are separate, intangible costs associated with the risks of wellhead and downhole operations. These risks include personnel injury, environmental / wellbore damage and the risk of not being able to re-establish production.

A method of repairing wellhead and downhole leaks in situ is needed, without having to mobilize expensive and risky rig or wireline operations.

Pressure-activated sealant. Seal-Tite International in Mandeville, Louisiana, has developed a new hydraulic fluid additive that is specifically designed to seal leaks in severe-environment hydraulic systems. What distinguishes this sealant is that it is pressure activated. The sealant will remain fluid in any hydraulic system until released through a leak site. Only at that point of differential pressure, through the leak site, will the sealant reaction occur and bridge across the leak, see accompanying Fig. 1.

The sealant is analogous to blood coagulating at a cut. The blood only heals the location of the cut. The sealant only "heals" the point of differential pressure, that is, the leak site. The remainder of the sealant stays fluid. It will not clog nor plug the hydraulic system or well components. The sealant can be left in the system or flushed out. Because each sealant formula is custom blended to the particular conditions of the leaking hydraulic system — whether it is tubing, casing, wellhead or SCSSV — the isolated sealing mechanism is possible, regardless of temperature, pressure or delay in reaching the leak site.

This sealant technology has successfully performed leak-sealant operations in a number of different applications:

• SCSSVs
• Wellhead tubing and casing hanger seals
• Casing / liner PBR seal joints
• Tubing pinholes and joints
• Subsea well-control systems.

The benefit of a pressure-activated sealant process is that, using only a skilled technician and a small, self-contained equipment dolly, custom-blended sealant is injected through the hydraulic system until the leak is corrected. The well may return to production without the expense and risk of using a rig or any downhole operation.

Case histories.  The product has been used successfully in the Gulf of Mexico, Alaska, North Sea, Malaysia and Abu Dhabi. The following representative case histories outline the capabilities of the sealant, the procedures used and the results of operations.

SCSSV leaks.  In the North Sea, a well had a severe leak of 1,000 ml/min in the SCSSV control line, which caused the well to shut in. Apprised of temperature, pressure and leak rate data, a custom-blended sealant formula was prepared. A technician ran troubleshooting diagnostics at the wellsite. Diagnostics indicated leaks, in both directions, between the V-packing of the wireline-retrievable SCSSV and polished bore nipple. The operating company was unable to retrieve the valve due to ongoing operations on an adjacent well which prevented access to the well with wireline equipment.

Using an SCSSV injection system, the technician pumped sealant into the hydraulic control line of the safety valve until the pressure-activated sealant, after only 10 min of pumping, had repaired the leak. Normal valve-operating pressure of 6,000 psi was maintained. After four hours, the technician performed function tests that verified full capability of the valve, and the well was returned to production.

Casing and tubing leaks. In Alaska, an inner annulus was communicating artificial-lift gas to the outer annulus. The operator was unable to bleed outer annulus pressure below 800 psi. A custom-blended sealant formula was atomized into the artificial-lift gas and injected into the inner annulus, while bleeding the outer annulus to atmosphere. Thus, sealant entrained with artificial-lift gas was carried to the leak site. After sealing the leak, outer annulus pressure dropped to 14 psi. The sealant allowed a successful tubing integrity test to 3,000 psi, and the well was put back on production. A similar procedure has been used in curing tubing leaks.

Wellhead leaks. In the Gulf of Mexico, after venting pressure from the wellhead hanger-cavity port and closing the pressure-release tool, there was a pressure gain to 150 psi — equal to surface FTP — within 30 min. The leak was identified as communication between hanger neck seals and hanger void. In preparation for repair, the operator installed a backpressure valve into the tubing hanger.

The technician filled the wellhead with custom-formulated sealant and installed the tree cap. Using a pump connected to the crown valve, the wellhead was pressured to 5,000 psi and held there until the leak was sealed. The technician cycled pressure between zero and 5,000 psi to force additional sealant into the hanger seals, until the bleed-off rate subsided to zero at 5,000 psi differential pressure. After the seal was verified, the backpressure valve was removed, excess sealant was flushed out and the well was put back online.

Summary. The use of pressure-activated sealant is a safe, low-risk, economical option to repair or replacement of leaking hydraulic systems. In most instances, use of this sealant and process will repair wellhead and downhole leaks in situ, without the need of mobilizing expensive and risky rig or wireline operations, thus reducing risk to personnel, equipment, well and environment.

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New multi-shot shut-in tool expands capabilities, saves time

The need for a high temperature, multi-shot system to perform multi-rate tests has led Geoservices to develop the new Build-up Evaluation Shut-in Tool (BEST). After several months of research and development, the tool has been run successfully on its first jobs, which were in Venezuela. The new tool expands the capabilities of the company’s Build-up Control System, which for several years has been used as a single-shot downhole valve. The older tool, however, had its limitations, i.e., no flow-in/flow-out capability, not rated for high temperatures, and it could not be used for injectivity tests.

The new test tool is an automatic, programmable, downhole valve, designed for closing and opening a well during production testing, Fig. 1. Its main purpose is to ensure quick and efficient tests. With minimum requirements for set-up, and a simple operating method, the tool provides a cost-effective means for evaluating reservoir pressure and temperature during flowing and build-up periods.

Increased capability.  Design characteristics and well-researched technical choices make the tool particularly easy to use. It is equipped with high-performance electronic circuits and mechanical devices that can withstand temperatures of 347°F (175°C) and 15,000-psi pressures, with a maximum D P of 10,000 psi. Its design allows up to 10 close / open cycles through a maximum duration of 40 days.

Programmable. Easily programed at surface with simple PC software, the tool is run on slickline and then anchored in the completion. When assembled with the appropriate crossover, the tool can fit most common completion types and sizes. Once it is set in the nipple, all surface equipment can be removed. This frees the slickline unit for use elsewhere during the survey. Since the tool works automatically without the need for any human intervention, it increases safety, particularly in difficult offshore job conditions.

Thanks to its special actuator, a sequence of tests can be programed for up to 40 days. Design of the sleeve valve ensures safe flow-in and flow-out operations, and significantly reduces the energy necessary to open the tool. Moreover, once the valve is closed, no external conditions can then open it; this applies to both producing wells and injection wells. In case of a problem with opening or closing the valve at the start or end of a test, the tool can always be retrieved after the equalizing device has been operated.

Test example. The chart in Fig. 2 shows the pressure recorded with a proprietary MQG-X gauge during a test in a gas-lift well. The tool was run in the hole in open position, then the well was opened at surface for 12 hours. After the programed flow-period had elapsed, the tool shut the well for a 98-hour build-up survey. The tool was pulled out after the automatic pressure-equalization phase.

The main advantages of the BEST lie in its easy use (simple programing, little maintenance) and its flexibility (wide range of well conditions). Since the tool is a downhole valve, its use obviously reduces the wellbore storage effect, which, when combined with high-accuracy memory gauges, provides more valuable build-up survey data.

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Movable submerged mixers improve drilling mud preparation, handling

Drilling mud comprises extremely small particles and has a thick consistency. Its settling velocity is therefore low, and sediment should not be a problem, if the contents in a tank can be kept in motion. But due to the combination of the irregular shape of tanks and the inefficiency of conventional mixing systems, sediment buildup is a time-consuming and expensive problem.

Flygt, an ITT Industries Co., headquartered in Solna, Sweden, offers a submersible-liquid-handling technology that not only provides complete mixing of any tank, but can also cut the energy consumption of the mixing operations.

Submersible mixer concept. In a submersible mixer, the motor and propeller are integrated in a compact unit. This results in practically unlimited installation flexibility, both in terms of where it is positioned in a tank and how the mixer’s jet flow is aimed.

This means that, instead of dissipating its energy against tank floors, baffles or facing walls — a problem with non-submersible mixers — the jet flow can be steered so that it follows the shape of the tank. With correct positioning and sizing of the mixer, the entire contents of the tank can be set in motion. By creating this motion, or bulk flow, solids are prevented from settling. Simply stated, this action:

• Creates one well-defined circulation with minimum losses
• Distributes the flow as evenly as possible throughout the tank
• Positions mixers to reach the tank’s "dead" zones.

An important benefit of the design is that each mixer can be mounted on its own guide bar, making it accessible and movable. A submersible mixer can be raised in a matter of minutes, without having to empty the tank. Because these compact machines are so easy to winch up and reinstall, a standby unit can replace a mixer or pump that needs servicing, essentially eliminating downtime.

Operating submerged, mixers and pumps take virtually no space. And submersibles do not need the extra head space that long-shaft units require when they are winched up. Expensive alignment equipment and time-consuming realignment procedures can be avoided. The absence of a long shaft also makes for a more robust and reliable machine.

With a high degree of installation flexibility, they can replace non-submersible units in most applications. And submersible mixers can easily be installed in tanks which previously had no mixers.

Having invested substantial resources in defining the fluid dynamics of submersible mixing, the manufacturer brings a high degree of predictability to mixing. With the help of PC-based sizing programs and a network of regional test labs, a mixing system can be configured that prevents sedimentation in any tank, of any shape and size.

The heavy-duty submersible mixers are available in a large number of different materials to meet varied corrosion, abrasion and temperature requirements. The mixers are manufactured in 1.9-kW to 30-kW (2.5 to 40 hp) versions. Pumps are available in a wide range of models, from portable 1.9-kW units delivering 150 l/min (40 gpm), to 450-kW mammoth machines with capacities of up to 150,000 l/min (40,000 gpm).

Two example applications. One of several operational criteria critical to uninterrupted performance of a drilling rig is maintaining the drilling mud’s uniformity. On the rig, operational mud requirements can vary greatly, with mud densities ranging from 13 to 21 ppg. Another variable is that mud tanks are often configured to "fit where convenient" rather than being designed with an efficient and easy-to-mix geometry — due to construction cost and limited rig space.

Diamond Offshore’s Ocean Winner is a semisubmersible rig designed with three tanks to store drilling mud. Measuring 30-ft deep and 20-ft wide, the geometry of these cylindrical tanks makes the use of traditional mechanical long-shaft mixers very difficult. These systems require costly tank covers that are capable of handling static and dynamic loads associated with mixer mountings.

Diamond installed two submersible, 15-hp, mixers in one of the three mud storage tanks on this rig, mounted on individual guide bars inside the tank. This technique is space-saving and provides optimal positioning of the mixers. Selecting the right height and angle of the mixers optimized mixing results.

Selection of a robust and versatile mixer that can effectively mix a variety of tank geometries and mud densities becomes an essential part of a successful and cost-effective drilling process. The submersible mixers and the Flygt-designed control system onOcean Winner have been living up to this performance standard since they became operational in mid-1997. Diamond subsequently equipped their new drillship, Ocean Clipper, with submersible mixers in its four active mud tanks.

In another success story, Baroid Drilling Fluids, in an attempt to improve the production of drilling mud, ran tests in 1996 with submersible mixers at its La Grange, Texas, facility. The company selected a mud preparation batch tank as a suitable application of the submersible mixers. The 25 ´ 8 ´6-ft tank, used for preparing a variety of water-based muds with specific gravities ranging from 13 to 18 ppg and viscosities of 15 cp, was equipped with baffles and an old mud gun system.

Two submersible mixers were installed on guide bars at different locations in the tank and were positioned and aimed for optimum mixing results. Two batches of mud were mixed and processed. When a batch was complete, it was pumped out to the storage tank and the tank floor was examined for sediment. Test results with the new system were better mixing, reduced mixing and batch times — and less additives were needed.

Copyright © 1999 World Oil
Copyright © 1999 Gulf Publishing Company