Drilling and gravel-packing sinusoidal wells

KEVIN P. McCOY, Warren E&P; and BRIAN VLASKO, Baker Hughes

To gravel-pack NWU 73-30, the first of six sinusoidal wells at the North Wilmington unit, two pumping units pumped water while a third pumped a sand-water mixture, all of which were blended at the wellhead.

As a first step to redeveloping its North Wilmington unit in California, Warren E&P implemented a pilot project drilling and gravel-packing sinusoidal-shaped horizontal wells. The project consisted of four producer wells and two injector wells with openhole sections 1,800–2,400 ft long and vertical amplitude planned at 110–120 ft. Significant deviations from the original well plan made gravel-pack completion of the wells challenging, but with the help of simulation models, injection rates and slurry weights were optimized, resulting in production rates in line with expectations. Based on the positive results, the operator plans up to 150 additional sinusoidal wells to optimize production in the area.

BACKGROUND

The North Wilmington unit (NWU), encompassing 1,036 acres, is on the northwest flank of the giant Wilmington oil field in California. Warren acquired a 100% working interest in the NWU in late 2005. By that time, 164 wells had been drilled and the field had been waterflooded. Warren doubled production rates to a gross average of 470 bopd through an intensive return-to-production program, but determined that, even at this higher rate, it would take at least 60 years to produce the potential reserves of the NWU. Experience in the thinner laminated sands at the Wilmington Townlot unit (WTU) suggested that horizontal wells would have to be drilled to maximize net pay and enable production of the remaining reserves at an economic rate.

The main producing formation at the NWU is the Ranger formation (Middle Repetto zone, Lower Pliocene age) composed of the F1, F0 and F sands. It is a sand/shale sequence that averages 350 ft in gross thickness (including the H through G layers) with an average 86 ft of net sand in the F1, F0 and F layers, for a net-to-gross ratio of 25%. The Ranger formation is a sequence of turbidite flows and overbank deposits with interbedded shales vertically and horizontally isolating many of the sand bodies.

The F1, F0 and F sands are not blocky. They are primarily composed of small lenses with limited lateral extent and marginal continuity and connectivity. Complicating matters, gamma-ray logs indicate that the Ranger sands are not very clean and are interbedded with very thin shale layers. A conventional well drilled into the NWU Ranger formation typically produces 20–25 bopd, a marginal rate.

Fig. 1. Wellbore paths incorporating a sine wave of 540° (top) and of 720°.

REDEVELOPMENT CONCEPT

Warren’s redevelopment of the Ranger formation has had uneven success. Given the laminated nature of the formation, return-to-production wells at the NWU and vertically drilled wells through the thinner crestal areas at the WTU have been economic, but disappointing.

Drilling. The problems with developing the NWU with vertical wells can be summarized as follows:
• Low oil production rates: Low reservoir pressure, combined with previously waterflooded sands, has resulted in 94% watercuts in producing wells.
• Multiple irregular sand lenses: The depositional environment has created a very heterogeneous reservoir in which interwell lateral communication is questionable. This complicates waterflooding and also leaves many areas in which oil has been bypassed and could be recovered if they were penetrated by a wellbore.
• Excessive well requirements and cost: Redevelopment would require some 85–90 costly vertical wells to be drilled and 60 or more wells to be converted from production to injection.
• Issues with new pipelines: Construction of flowlines from new wells or new sites is nearly impossible within the cities of the Los Angeles basin.

Warren has had great success employing horizontal wells in the Tar formation at the WTU, adjacent to the NWU. However, in a formation with multiple pay zones and laminated sands, such as the Ranger formation, horizontal wells have serious limitations. A horizontal well can typically target only one productive horizon. At the NWU, the irregular sands are not necessarily connected vertically, thus limiting productivity from a purely horizontal well. Even a well drilled with some vertical or corkscrew component would only intersect some of the laminated sands. Furthermore, the thin, irregular sands enter and exit the well path, making directional drilling difficult.

The question then arises, “What is the optimal way to drill and complete a well in vertically discontinuous sands, such that it will have a reasonable payout and a realistic chance of success of being both drilled and completed?” With an average thickness of 130 ft from the top of the F1 sand to the bottom of the F sand, three typical well designs come to mind: vertical (up to 60°), horizontal and multi-
lateral. Given the reservoir complexity and challenging geometries, the solution had to connect multiple marginal zones and improve project economics.

Each of the conventional options utilizing vertical or horizontal completions was dismissed. Multilateral wells appeared to be a viable solution; however, after evaluating cost, complexity, wellbore limitations and planning time, multilateral wells were determined to be risky and uneconomic for this application.

This left the engineers with no easy solutions. A significant change in thinking resulted in a proposal to drill a wellbore with the cross-sectional shape of a sine wave to maximize penetration of existing zones and possible bypassed lenses.

A sinusoidal or multi-penetrating wellbore (Fig. 1) can be considered as multiple individual wellbores, but with significant logistical and cost benefits. Alternatively, it can be considered as multiple distinct high-angle wells with one common, producing wellbore. A wellbore path incorporating a sine wave of 540° will penetrate the three major zones of the Ranger formation three times. A wellbore incorporating a 720° sine wave will penetrate the Ranger sands four times.

Multiple-well equivalencies help increase the overall number of irregular lenses that are penetrated, maximize contact with the reservoir and minimize the number of primary wellbores, tubing strings and wire-wrapped screens needed for a given well. As Warren drills wells from concrete cellars, an important advantage of a multiple-zone well is that it significantly reduces surface land, piping and electrical infrastructure requirements. Simulation runs predicted that the number of equivalent wellbores in such a well would roughly correspond to the multiple by which production would increase, compared with a single vertical wellbore through the pay zones. The primary challenge was that this was a largely untested method for both drilling and completion of the wells.

Completion. Defining the completion determined how the producing interval would be drilled. Fifteen completion types of varying technique, complexity and cost were evaluated based on six criteria (in decreasing order of importance):
Type of drilling required
1. Mechanical ability of the rig to run the necessary equipment
2. Complexity of the completion and of the equipment required to run it (including availability in California)
3. Expected durability and longevity of the completion
4. Chance of success and overall cost, including rig time and other contractors
5. Skin factor and optimal producing mechanism.

Eleven completion options were easily dismissed based on complexity or cost. The remaining options were gravel-pack or multilateral completions. The multilateral option at first glance appeared to be a competitive solution; however, mini-sinusoidal well paths would still need to be drilled to penetrate the numerous sand lenses.

The general performance of the horizontal, openhole gravel-packed Tar wells at the WTU had proven the success of gravel-packing, with typical wells producing 450 bpd of total fluids at drawdowns of 20–50 psi. The low cost and familiarity of gravel-packing also played important roles in the choice of this completion method for the NWU sinusoidal well program.

Utilizing the NWU’s Satellite 7, planning for the drilling and completion of six wells, along with accompanying facilities, proceeded for six months until drilling commenced April 26, 2008.

IMPLEMENTATION

Planning commenced in earnest in October 2007, with weekly meetings to ensure that goals were met on schedule. Significant issues were quickly realized on both the drilling and completion sides. To the operator’s knowledge, no one had ever drilled or completed a well with the wellbore trajectory that was being proposed. Vendor after vendor said it could not be done. The project looked like it was doomed before it started.

Significant work on the torque-and-drag calculations indicated that drilling the proposed wells was possible with certain drillstrings and a rig with a large enough hookload and top drive. A review of steerable drilling systems was undertaken, and a point-the-bit steerable system was chosen. During implementation, this system was found to significantly increase drilling efficiency through 100% drillstring rotation, the elimination of oriented drilling with bent-subs and motors, and improved hole cleaning, which is very important to ensure successful gravel-packing.

Planning for the well completions lagged substantially until Baker Hughes was contracted to find solutions to the complex issues associated with completing this type of well. What followed was an extensive literature review and interviews with various North American vendors to collect information and recommendations. Once a set of options had been identified, the land, facilities, drilling and completion teams at Warren met regularly to identify issues that would impact the timing and the equipment that could be run.

The service company reviewed the options, incorporated its experience at WTU and ran simulations for several months. A data review of prior horizontal drilling and completion jobs revealed that initial difficulties with gravel-packing had been solved by extensive analysis and modifications to procedures. Using the data from these jobs, the service company improved its simulation modeling. Based on this modeling, the company established a detailed, written procedure covering all aspects of the completion process including safety, testing, startup and shutdown of equipment.

Basic well design. The wells were drilled from surface to the intermediate casing point, at which time 10¾-in. casing was run to 500 ft (cemented in place) and 7⅝-in. casing  was run into the F1 and F0 sands (cemented to above the freshwater base), Fig. 2.

The sinusoidal section was then drilled using a 6¾-in. PDC bit and M-I Swaco’s Flothru reservoir drill-in fluid. Build angles did not exceed 7°/100 ft, to minimize torque-and-drag issues and to ensure that the stainless steel wire-wrapped screen could be pushed to TD without damage. The vendor’s point-the-bit system allowed for in-gauge holes to be drilled in the soft, semi-unconsolidated Ranger sands. The system used an azimuthal deep resistivity tool, which allowed for continuous readout of formation data. In contrast, systems using push-the-bit steering can only acquire data while the bit is being rotated. Push-the-bit systems also cause corkscrewing of the wellbore, which can negatively impact the gravel-packing operation.

The mud system helped minimize skin damage and ensured high permeability in the final completion. The fluid has a high tolerance to drilled solids contamination and is designed to eliminate the need for chemical breakers after drilling and completion.

Fig. 2. Proposed well path of the NWU-73-70 sinusoidal producing well.

Gravel-pack design. While inherently more difficult to implement than a cased and cemented hole, gravel-packing generally provides a superior completion with significantly lower skins. The easiest method involves gravel-packing within a casing string, but even this technique has inherent difficulties. Generally, the base casing should be cemented in place to avoid movement and subsequent packing of the surrounding formation. Next, the ID of the outer casing should be large enough to provide at least a ¾-in. space between the wire-wrapped screen and the inside of the casing, ensuring that a satisfactory amount of sand covers the screen. This requirement, in itself, can be a significant limitation in the design of the final completion.

Warren typically runs 7⅝-in., 26.4-lb/ft intermediate casing strings. The maximum casing diameter that could be used over the producing interval would typically be 5½-in. casing inside a 6¾-in. hole. This decision would subsequently require running a 2⅞-in. wire-wrapped screen to ensure sufficient gravel around the screen to avoid cutting out the screen; no further remediation can be attempted if the 2⅞-in. screen fails.

For these reasons and based on success in the Tar wells, it was decided to complete the sinusoidal wells with 4½-in. wire-wrapped screen, centralized at every joint and halfway in between. To help reduce the chance of liner failure while running over the peaks and valleys of the openhole section, a heavy 316L stainless steel wire-wrapped screen liner (4½-in. 11.6-lb/ft, 0.012–in. gauge, 90H/140R) was selected.

Table 1. Well geometry results for NWU sinusoidal wells

Table 2. Gravel-pack results for NWU sinusoidal wells.

Fig. 3. Measured depth vs. true vertical depth for the 2,789-ft (horizontal length) openhole section of the NWU 73-30 well.

Simulation. The service company approached the modeling process by first looking at data collected from the Tar horizontal gravel-packs performed over the previous two years. A database was constructed incorporating treatment and return flowrates, treating pressures, hole inclinations, dogleg severities, lengths of completion intervals, and percentages of theoretical gravel-pack sand placed. The database was used to compare parameters such as length of gravel-pack successfully placed vs. dogleg location.

The development of accurate and realistic simulation parameters allowed the service company to model the planned gravel-packs with confidence. An accurate roughness factor was very important when evaluating expected pressure outputs from the gravel-pack simulator. The operator needed to know with confidence that it could successfully pump gravel over the entire production interval without fracturing the well, while still maintaining sufficient velocities to maximize the probability of achieving a successful gravel-pack.

Accurate design parameters were developed from running post-job simulations using true data gathered from the Tar horizontal wells. Multiple simulator runs were then performed.

Fig. 4. Tubing pressure and flowrates over time during the gravel-pack operation for well NWU 73-29i.

Fig. 5. LWD plot for NWU 73-30.

Gravel-pack execution. The six sinusoidal wells (Table 1) had an average maximum length of 7,387 ft (MD)and an average openhole section of 2,536 ft (horizontal length). Within the sinusoidal sections, the greatest amplitude (trough to peak) drilled was 185.5 ft. The maximum height from the lowest part to the highest part of the openhole section was 229.9 ft. These heights were substantially different from the initially planned maximum heights of 110–120 ft.

Well NWU 73-30 illustrates the difficult challenges faced by the team, Fig. 3. The well deviated substantially from the planned 110–120-ft maximum height. While gravel-packing horizontal wells with deviations of 10–20 ft from horizontal is commonplace, carrying sand in a low-viscosity fluid up a hill equivalent to a 23-story building had never been done.

NWU 73-30 was the first well gravel-packed. Based on simulation work and past experience gravel-packing the Tar wells, it was realized early on that significantly higher rates of injection and lower slurry weights would be required to effectively pack the NWU wells. Pumping rates and pressures were increased to overcome any deviations that were higher than expected in the sinusoidal section. Gravel concentration was kept as low as 0.25 lb per clean gallon of fluid to reduce hydrostatic head on the formation and to increase sand transportability. Gravel-packing was completed on some wells with almost 100% losses. Although these incidents were rare, they should be planned for in future operations.

Friction created by fluid flowing through the drill pipe, screen, tailpipe, casing and surface iron added a tremendous amount of pressure to the system. Baker Hughes and Warren E&P began looking into ways to eliminate or reduce friction pressure in the system, to allow pumping at a higher rate. Return flowline and valve diameters at surface were increased, resulting in a reduction of friction pressure. Modifying the discharge on the back side of the casing relieved the backpressure that is normally encountered in fluid metering, significantly improving fluid rates at 300–400-psi lower surface injection pressures, Fig. 4. The pressure reduction provided an increased margin above the fracture pressure, while the higher fluid rate increased the likelihood of a successful gravel-pack across the entire production interval, Table 2. The lower backpressure can also be expected to improve equipment durability.

PRODUCTION PERFORMANCE

Figure 5 shows a logging-while-drilling (LWD) plot of the typically drilled sinusoidal well. The yellow bands correspond to sandstone and the green to the interbedded shales. A typical vertical well averages in the range of 70–90 ft of net pay, whereas a sinusoidal well intersects up to 1,500 ft of sand with resistivity greater than 5 Ω-m. This is a substantial increase in footage and is borne out in the performance of the individual wells and improved economics.

Warren E&P and Baker Hughes successfully completed additional sinusoidal wells at the Wilmington Townlot unit in 2010, in the Upper Terminal formation. Production performance has exceeded expectations. Warren E&P plans to drill up to 150 additional sinusoidal wells at both the NWU and the WTU to maximize recovery. Redeveloping the reservoir with sinusoidal completions will enable the operator to more efficiently reactivate the field from fewer surface locations and interconnections. This novel approach will also decrease liability, cut costs, reduce the potential for pipeline breakage, and largely eliminate the difficulties associated with laying pipeline within the city of Wilmington. 

ACKNOWLEDGEMENTS
The authors thank Ron Morin and Steve Heiter of Warren E&P and Mike Gleason of Baker Hughes for their input.