Well Completion and Simulation

Using simple salt water, (NaCl or K2CO3), and electrolysis, produces a more cost effective, environmentally benign biocide, HOCl (hypochlorous acid), and/or an environmentally benign alkaline ( KOH) , production enhancing, super water wetting, well treatment solution. The production enhancement from using small 1000–3000-gallon alkaline (KOH) Catholyte treatments on two new wells in the S.E.

OBJECTIVES/SCOPE: 
Cleaning out a lateral is a powerful tool for restoring production in mature wells, but sometimes the hydraulics will not allow circulation with fresh water. An interesting technique for cleaning out such laterals has been field tested in the Delaware Basin, and it has potential application in many basins. As laterals age, a proper cleanout using this new method can restore production after a frac hit, prepare it for a refrac or for spotting acid across the lateral, run casing patches, clean out the top of a fish, and numerous other applications.

The Permian Basin began production in the 1920’s.  With that production of hydrocarbons has come the production of a lot of water.  In 2002 it was estimated that the production of water was 400 million gallons per day and that volume has increased steadily.  In addition, to water production, many reservoirs have reached an age where the paraffin and asphaltene content of the produced crude has increased.  Also, corrosive fluids production has increased, yielding deposits in tubulars.

One of the most expensive issues while workover operations are fishing and sometimes it ended up being a non-successful operation when the fish is left in the hole. The time expended trying to pull a fish in horizontal wells is particularly long and the costs are high. Proper planning and good practices should reduce the risk associated with this problem but as a contingency, a new tool has been incorporated in more than 150 installations in the Midland and Delaware basin during 2022.

A new gas separation technology was released last year with the goal of creating a substantially increased volume capacity and therefore significantly improved separation quality through application of a process known as limited-entry. This process is more commonly applied to well fracturing and other stimulation procedures wherein the principle is applied to create an equal distribution of fluids to be pumped into an expansive length of producing formation or a variety of formation qualities at once.

Historically, managing and inhibiting corrosion, scaling and paraffin deposition downhole required surface chemical remediation. Numerous application scenarios involve truck treating, bulk tank placement and chemical injection.  A commonly used modification of this principle involves dropping solid chemical compounds down the backside of the wellbore and ultimately landing into the rathole (long cylindrical cavity inside the well casing, but below the tubing string) where the accumulated mass can rapidly dissolve.

While tubing anchors are extensively used to pull tension on production tubing to improve rod pump performance, several factors need to be considered regarding the placement of the anchor. This paper will discuss field examples of tubing anchor setting strategies, mechanisms that can lead to anchors getting stuck, and alternative anchor setting strategies.
 

Environmental concerns and increasing costs are creating a need for a polymer that will allow the use of a high salt, high hardness water in the making of a viscosified frac fluid. Any new polymer would also need to tick the boxes for cost, rheology, HS&E characteristics as well as breaking in the reservoir. Past development efforts have focused on improving organic-based polymers. A new approach was taken and a shift was made to the use of silica-based polymer.

Friction reducer is a hydraulic fracturing fluid additive meant to lower costs by decreasing the friction pressure in tubulars during pumping operations. High viscosity friction reducers (HVFRs) have become increasingly popular in well stimulation applications in lieu of conventional slick water fluid systems involving linear and cross-linked gels. However, various factors must be considered when assessing the effectiveness of using HVFRs under certain frac operation conditions.

This paper will present a methodology being applied which examines well heterogeneity, and designs the diversion strategy based on actual reservoir properties.  Estimations of minimum insitu stress at each cluster are combined with estimates of stress shadow effect both from previous stages and between treatment clusters, to determine at which pressure each cluster will accept fluid.  This data is then used to bin clusters into the ones which will be treated first, followed by a diverter slug, then second and potentially third.