Advance industry’s ability to cost-effectively optimize fracture stimulations, lowering the cost of completing low permeability gas wells and improving productivity. The objective is to develop and demonstrate a method for controlled mixing of fracturing fluid components at the completion interval in a manner that facilitates the monitoring and assessment of fracture stimulation performance in “real time,” enabling operators to adjust fracturing parameters in order to dynamically optimize stimulation results.
RealTimeZone, Inc. – Project management and all research products
Roswell, NM 88203
Pumping fracture treatments at high pressures is expensive and can be a safety hazard, particularly in wells with older tubulars in mature fields. For these reasons, stripper wells are often rejected as candidates for stimulation treatments that could result in improved recovery. Fracture stimulation problems may arise when the pressures required to pump gelled fluids reach a limit, requiring the operator to prematurely terminate the treatment to avoid rupture of surface equipment or wellbore tubulars. Excessive treating pressures may also occur abruptly during the fracturing process as a result of premature screenout (a high rate of stimulation fluid bleedoff into the reservoir which causes the proppant to compact within the fracture and wellbore). A second problem can arise with the timing of inhibitors. Highly viscous gels are desirable for effective transport of proppant. However, if gelling occurs before the fluid is pumped, the efficiency of the job may be compromised due to higher pressures and lower pump rates. With surface-blended fluids, chemical inhibitors may be mixed at the surface to time-delay activation of cross-linked polymer gels. But if gelling occurs too early or too late, either premature screenout or poor proppant transport can result. The high treating pressures that result can crush proppants in the fracture, creating fines, accelerating fracture closure, and causing formation damage. High treating pressures also lower pump rates, reducing the amount of fracturing fluid and proppant that can be pumped, and increasing horsepower requirements and cost.
The results of this project offer the industry with a new downhole mixing technology which will allow wells once designated as unsuitable for hydraulic fracturing to now be stimulated. This will increase the number of recoverable reserves. The technology offers numerous advantages including lower costs, lower treating pressures, reduced horsepower requirements, and the ability to make near instantaneous changes to a stimulation while in progress. The reduced treating pressures also reduce the safety hazards associated with extremely high pressures. With the advantages mentioned, this technology could have a significant impact on revitalizing depleted wells which are scheduled for plugging, with the end result being increased production in the U.S.
This project was designed to develop and demonstrate a dual-fluid stimulation process that involves mixing of separate fluid types downhole to create a composite fracturing fluid at the formation. Downhole-mixing is accomplished by dual injection of different fluids for admixture next to the perforated interval, via coiled or conventional tubing and the tubing-casing annulus. Downhole rheologic properties and proppant concentrations of the mixture may be modified “on the fly” by adjusting surface pressures and rates on each of the two fluid injection routes. Downhole-mixing can also be used to create different fracturing fluid phases, and thereby induce real-time viscosity inter-fingering in the reservoir fracture or fractures, focusing proppant placement and facilitating control of proppant concentrations. This methodology may be combined with real-time fracture monitoring to enable an operator to control fracture propagation and improve fracture geometry and proppant concentration and placement.
During a typical fracturing treatment sequence, fracturing fluid is surface mixed and pumped in pre-pad, pad, proppant, and flush stages. The fluids, which might also include gelled hydrocarbons, are pumped down the casing while the tubing is a “dead string” that provides the operator with a means of monitoring bottomhole treating pressure during the fracturing process. With downhole mixing, aqueous gel with nitrogen and proppant is pumped down the casing and liquid CO2 is pumped concurrently down tubing at constant or variable ratios during successive treatment stages. Downhole-mixing forms a composite fracturing fluid above or adjacent to the perforations. Pump rates are varied for the purpose of achieving desirable fracture growth and proppant placement within the reservoir zone. In addition, fluid rheology may be selectively altered, in real-time, as a result of modification of relative pump rates at the surface of tubing and casing. The net composition of the composite fracturing fluid is variable, as a function of the rates at which the tubing and casing components are pumped. A key element of this methodology is the suite of algorithms and calculation procedures that have been developed and tested to accomplish these changes downhole with confidence.
RTZ demonstrated the downhole-mixing technique in fall 2001 in a 12,300-foot Morrow gas well in the Sand Point field of Eddy County, NM. The treatment consisted of a methanol gel with 7,000 pounds of bauxite proppant pumped down the annulus and 40 tons of liquid CO2 pumped down the tubing. Tubing pressure never exceeded 6000 psi, and the casing side was never above 5000 psi. If the job had been pumped in the conventional manner, the pressures would have averaged closer to 10,000 psi. Liquid CO2 was used because after the proppant has been placed in the reservoir fracture, the drop in bottomhole treating pressure turns the CO2 from liquid to gas, allowing the fracturing fluid to be produced back from the formation at a faster rate. Originally scheduled for abandonment, the Sand Point well’s post-fracture production was 200-250 Mcfd. A post-fracture tracer log showed the treatment had been placed in the zone as designed.
RTZ performed another treatment in an Eddy Co. well completed in New Mexico’s Willow Lake Delaware oil reservoir. The Willow Lake well was considered to be a dry hole. The Delaware sandstone showed about 40 to 50 ft of net pay at about 5000 ft depth, with a wet zone 40 to 50 ft thick directly below the pay, and no stratigraphic barriers. Most wells in the area produce at 60 to 90 percent water cut because hydraulic fractures invariably grow out-of-zone. Tracer logs have revealed hydraulic fracture heights of 100 to 200+ ft in most wells in this field. RTZ pumped gelled lease oil and proppant down the tubing while pumping CO2 down the annulus, carefully controlling rates to achieve the appropriate mixing at the perforations. The result was an economic well; 8-10 BOPD at only 20 percent water cut. A third test well completed in spring 2002 was an acid-CO2 treatment pumped to a Wolfcamp reservoir at 10,500 ft, also in the Permian Basin of New Mexico. By pumping the acid down the tubing and the CO2 down the annulus, treating pressures could be maintained around 5800 psi, rather than 9000 to 10,000 psi. This test was completed using only two acid trucks and was also successful.
A methodology has also been developed to combine this downhole mixing methodology with a downhole, real-time, surface readout fracture monitoring system to give an even more accurate picture of where the fracturing fluids are going.
and Remaining Tasks:
The project is complete. Even though the technology is not exclusively licensed, it is available commercially. The ability to stimulate wells with less pressure, less horsepower, and less fuel enables wells with older tubing and lower incremental reserves to be stimulated economically.