Completion technology during the 1990s evolved through incremental steps. Driven by the need to produce from greater water depths, the economic operating environment changed significantly from shallow water satellite and platform operations.
A new packer design incorporates a new barrel slip that aids in centralizing the element package and increasing slip to casing contact, helping prevent casing damage and provide a high-strength packer.
Today, completion drivers focus on enhanced well productivity, increased completion reliability, reduced cycle time, reduced well interventions, and improved logistical support, while conducting all operations in harmony with the environment. These trends will remain the drivers into the foreseeable future.
Within the last 10 years, the Gulf of Mexico has experienced the first high rate producing wells (> 10,000 b/d of oil). These deepwater, high-rate-capable wells present many challenges, including:
- Extended reach wells with lengths to 30,000 plus ft,
- Prolific wells with oil production rates greater than 50,000 b/d,
- Completions that maximize reservoir recovery (30-50 million bbl) without intervention.
Productivity is the desired end result of a properly planned and executed completion. To achieve this result, sand control placement technology has evolved from gel and water packing, to high rate water packing (HRWP), frac pack (FP), open hole horizontal gravel packing (OHHGP) and a variant of HRWP/FP, in which frac pack techniques are applied to HRWP in order to maximize the amount of sand placed behind pipe. Frac pack and open hole horizontal gravel packing have delivered the most prolific wells to date in the Gulf of Mexico: 50,150 BOE after FP, 46,624 boe after FP, and 40,908 boe after OHHGP.
Advanced perforating system has a propellant sleeve over a conventional perforating gun assembly. When the guns are detonated, the propellant sleeve is ignited instantly, producing a burst of high-pressure gas. This gas enters the perforations, breaking through any damage around the tunnel, creating fractures in the formation. As the gas pressure in the wellbore dissipates, the gas in the formation surges into the well-bore carrying with it damaging fines.
- Specialized fluid systems: Placement techniques and tools are continually being improved. Specialized fluids have been developed to enhance productivity. These include a seawater-based borate fluid that provides higher regained conductivity and better cleanup through reduced polymer loading and advanced breaker technology without sacrificing proppant transport efficiency.
- Improved downhole equipment:
To handle the higher pressures encountered during frac pack placement, downhole equipment required upgrading. Upgrades included utilizing higher yield material on downhole assemblies and increasing packer differential ratings. A bbl slip design was incorporated in the packer that aids in centralizing the element package and increasing slip to casing contact. This increased contact area of a radially deployed 360° slip disperses pressure-induced loads preventing casing damage and provides a 10,000-psi production rating and 12,000-psi frac rated packer.
- Perforating and perforation cleaning: In the search of incremental productivity improvements for cased hole, deepwater completions, a new technology has been applied recently to the perforating and perforation cleaning process. Thin sleeves made from solid propellant have been attached to tubing conveyed perforating gun. Perforating charges ignite the propellant sleeve to produce a burst of high-pressure gas. The gas enters the perforations, breaking through any damage around the tunnel, and creating fractures in the formation. As the gas pressure in the wellbore dissipates, the gas in the formation surges into the wellbore carrying with it damaging fines.
This technology was first developed for formations with lower permeability that are typically treated with hydraulic fracture stimulation. For deepwater completions, the technology has also been applied to completion zones where frac pack sand control treatments are the treatments of choice for productivity and longevity.
In those applications, near wellbore tortuosity restricted completion zone injectivity, prevented fracture propagation, and limited sand placement to volumes more typical of HRWP treatments. Application of this perforating technology to offset wells demonstrated superior post-perforating fluid loss, improved injectivity, and increased sand placement behind the casing.
- Intelligent completions: Maximizing recoverable reserves from each interval is one of the major goals in deepwater. Intelligent completions allow for selective or commingled production. With pressure gauges and infinite position control valves, the operator can better monitor the reservoir, change producing intervals or interval contribution, and maximize net present value (NPV) without intervention.
Completion reliability for the life of the reservoir is critical. With intervention costs running in the millions, it is imperative that both deepwater wet and dry completions can be produced to depletion.
- Computer modeling: Up-front computer modeling is essential to frac pack and openhole horizontal gravel pack placement. Several studies have shown, for example, that frac packs that result in significant buildups of net pressure during the treatment tend to outperform those that do not build up any net pressure. Similarly, the successful placement of a open hole horizontal system using the a/beta placement technique requires that the injection rates be sufficient to overcome the leakoff to prevent any bridging without exceeding breakdown pressures.
The optimization and successful placement of these two completion types involves the consideration of many factors such as the formation properties, downhole equipment capabilities, and treating fluids. These factors make every completion a unique system and the design must be tailored for each completion. This is best done through the use of computer models. It is also essential that pre-job calibration testing be performed to validate and fine-tune the model. The use of the on-site calibration of the open-hole gravel pack model can help prevent a premature screenout of the treatment.
- Increased rate capability/erosion resistance for downhole tools: Early gravel placement methods provided the safety factor for prevention of downhole tool erosion. With the advent of frac pack and the demand for higher pump rates and proppant volumes, downhole tools are now the limiting factor. Gravel exit port design improvements and positioning in the packer assembly were required to increase rate capability and eliminate erosion on the wellbore casing.
Other refinements included upgrading tool material to P-125, weight down position during pumping, and activated ball check that prevents swabbing during tool movement. These refinements have culminated in a tool system that met the requirements for the Shell Ursa A-7 job design. This job was pumped at a maximum rate of 40 bbl/min and a sustained rate of 35 bbl/min with a sustained pumping pressure of 10,500 psi. The treatment involved successfully placing 94,000 lb of proppant below the crossover.
- Innovative tool designs: Features, such as the weight-down circulating feature, were incorporated into the OHHGP tools. Placing gravel across long open-hole horizontal intervals required a complete review of hole clean up processes, drill-in fluids selection, filter cake removal techniques and chemicals, tool requirements, screens and pumping practices. The review of tool requirements produced horizontal gravel packer service tool designs that allow circulation out the end of the screen during deployment and then can be converted after the packer is set to a crossover service tool. Special tattletale screen assemblies have also been designed for the end of the production screen that can be plugged immediately after the hole has been packed. This feature prevents any sand production that may occur as a result of a circulation damaged tattletale screen or as a result of incomplete gravel alpha wave coverage at the end of the transport path.
An even more recent improvement to horizontal tool systems has been the additional feature that insures full hydrostatic pressure is constantly applied to the horizontal borehole during the packer setting and testing process. This prevents bore hole collapse during the setting process that was not only possible, but actually happened with earlier horizontal gravel packing systems.
- Fluid loss control devices: Mechanical fluid loss devices have been a part of gravel packing for the last 30 years. Ceramic flappers are common but produce debris that can cause damage to subsea chokes. To improve reliability of subsea chokes, an alternate fluid loss device was developed that does not create debris. It is an expendable ball and seat check valve. It is a one-time device that is deployed off the end of the wash pipe. Once deployed, the ball falls on seat, and a check valve is created to stop fluid loss down through the gravel pack screen. At any subsequent time, the ball can be expelled and allowed to fall to bottom by pressuring up on top of the ball to the releasing pressure which is typically about 2,400 psi. The consistent performance of this tool has led to the replacement of ceramic flappers even in deepwater dry tree completions where the produced debris is a lesser concern.
- Controlling scale deposits: One other overlooked issue is reduced production from scale deposits in formations that are sensitive to HCl acid. Given the lower BHT of most deepwater formations, organic acids may not provide the desired results. Solid inhibitors are now added during the frac pack proppant stages, to prevent scale deposits caused by initial water production.
Cycle time and logistics
Cycle time reduction and logistic improvements are critical to improving the cost environment in deepwater. Higher rig rates for deepwater completions have pushed the requirement for working in marginal weather conditions.
- New generation vessels: A new generation frac vessel is now used for deepwater work. Prior vessels were mainly converted workboats that had limited dynamic positioning (DP) capabilities along with limited storage capabilities. The new fit-for-purpose stimulation vessels are wider and longer. The larger engines, bow thrusters, and dynamic positioning equipment allow for working in weather conditions that sent the first generation stimulation boats to the beach.
In addition to weather, the deepwater reservoirs are requiring increased pumping and proppant handling capabilities. Recent frac packs have treated at pressures of 10,000+ psi and 40 bbl/min. Job designs with 300,000 lb and greater of proppant are increasing. Even with the larger vessels, space is still limited. Modular skid, automatic, remote control equipment has been designed and installed to maximize deck space. For example, Halliburton's new generation boat boasts four 1,500 cu ft sand systems (additional storage below deck), five 2,000 hhp pumps, one 50 bbl/min frac pack blender, QC laboratory, state of the art control room, and 1,000,000 lb proppant capacity.
Freshwater based frac fluids coupled with limited fresh water storage have reduced vessel availability in the past. To enhance vessel availability, a seawater based frac fluid was developed. This fluid technology requires specialized metering equipment on the blenders to maintain strict quality control. By eliminating the batch mixing that was formerly required, residual fluid disposal costs have been reduced.
- Advanced subsea hanger system: To eliminate the uncertainty (risk) and the time (cost) required for the space out of the subsea tubing hanger, a hydraulically released telescoping joint with a very long adjustable stroke length has been developed and successfully deployed. After stabbing and landing the production seal assembly into the seal bore packer, application of a compressive load will initiate transfer of hydraulic fluid through a metering system in the telescopic joint. After a short metering period, the telescopic joint unlocks, unseals and can be collapsed. Since the stroke length is long (60-120 ft is typical), the subsea tubing hanger can subsequently be landed with confidence without the need to run space out logs and without the requirement of a zero error tolerance tubing tally. After the subsea hanger is landed, the up-hole hydraulic production packer is set. The telescopic joint can be re-locked and resealed by brief application of tension. The telescopic joint also incorporates an emergency backup unlocking feature.
Intervention in deepwater subsea completions is a costly proposition. It is not just the cost of intervention, but also the lost production and increased risk of damaging the wellbore. The reasons for intervening are many, but can involve scale buildup and the need to perform some type of wireline operation. Solid inhibitors are now being added during frac pack treatments to prevent water production scale deposits. To reduce the need for wireline, intelligent completion technology is gaining favor. The first two completions in the Gulf of Mexico were installed during 1999. The remote control of the downhole valves eliminates the risks and intervention cost for shifting sleeves in selective completions.
Environmental compliance is part of the business model of both operators and service providers. One upstream operator has a goal of "zero" discharge by the year 2005. Collecting and transporting fluids back to shore for disposal is an added operational expense. A seawater-based fluid system is now available with a formulation that is environmentally acceptable in the Gulf of Mexico. A liquid gel concentrate and surfactant were developed to pass US government regulations, without sacrificing the mix on the fly benefit of the original fluid.
As the industry develops both the moderate and larger billion bbl reservoirs, a complete understanding of the reservoir geology to optimize well placement is essential. Large mono-bore completions will be required to maximize production and reserve recovery from some large reservoirs. Mono-bore completions for 7- in. and 9 5/8-in. will be required to reached the >50,000 b/d oil and >100 MMcf/d gas pro duction rates. Completing extended reach wells with lengths > 30,000 ft will require smart tool assemblies that can perform multiple tasks to reduce cycle time.
Placing power generation downhole will eliminate the need for hydraulic and instrument lines thereby simplifying tubing running. Improvements in fiber optic and acoustic telemetry communication will further enhance communication reliability. The ability to have real-time information and control of a well, even in remote locations is rapidly becoming a reality. Recent advancements in artificial intelligence and neural network technology could also lead to the development of intelligent agents that can detect potential problems and provide solutions without significant human interaction.