This experiment was designed to compare the immediate fixation strengths of various methods of soft tissue fixation techniques. The fixation techniques tested were the barbed staple, stone staple, suture techniques, screw with spiked plastic washer, and the screw with spiked soft tissue plate. Cadaveric soft tissue specimens were classified into three distinct morphologic types: capsular, tendinous, and extensor mechanism tissue. Each specimen was fixed to bone by one of the fixation techniques. The specimens were loaded in a cyclical fashion until fixation failure occurred. One hundred thirty-seven trials were performed. The screws with the spiked plastic washer and soft tissue plate proved superior overall for all three tissue types. The stone staple was the poorest technique tested. Therefore, if cyclic loading or tension is anticipated at the fixation site, the fixation technique of choice would be the screw with spiked plastic washer or soft tissue fixation plate.

The purpose of this study was to evaluate the clinical outcome of patients treated with limited immobilization and early motion after repair of acute Achilles tendon ruptures. Thirteen consecutive patients with complete ruptures of the Achilles tendon were identified, repaired, and rehabilitated with early motion starting an average of 10 days after surgery. Active range of motion was begun at an average of 23 days and weightbearing in a walking boot was started at an average of 3.5 weeks after surgery. The average length of follow-up was 27 months. Twelve of 13 patients returned to running activities in an average of 3 months. All 12 patients who participated in lateral motion activities before their injury returned to similar activities in an average of 7 months. The patients rated their overall status at an average of 93% of their preinjury level. Follow-up Cybex testing demonstrated plantarflexion strength averaging 92%, plantarflexion power averaging 88%, and plantarflexion endurance averaging 88% of the nonindexed extremity. Early range of motion after Achilles repair is safe and there is no increased risk of rerupture in compliant patients. The patients achieved good return of plantarflexion strength, power, and endurance.

A new ultrasonic leak detection logging tool conveyed on electric line, and recently on wireline in memory mode, has been introduced which can detect leaks as small as 1/2 cup per minute. This revolutionary tool has been used to accurately identify leaks in tubing and behind pipe. Wells that otherwise would immediately be slated for a rig workover (RWO) have been repaired with non-rig solutions. Ultrasound energy has very rapid attenuation and the ability to transmit through various media and behind pipe. These attributes allow pinpoint accuracy for leaks as small as 0.0024 gallons per minute (gpm). The tool incorporates data acquisition equipment and filtering algorithms which allow continuous logging. The technology is far superior to old-style noise logs which require time consuming stationary counts. To date, BP has run 21 ultrasonic leak detection logs in Alaska fields with an 81% success rate. The recent ability of this tool to be conveyed in memory mode has opened up additional logging opportunities. This has led to the development of a new technique using nitrogen to identify wells that leak only to gas. Application of this tool has great significance for any operator concerned with well integrity, and particularly, in areas where rig workovers are expensive including remote, offshore, and arctic locations. Introduction BP operates several enhanced oil recovery and waterflood oil field which have experienced well integrity issues as the field matures. Non-rig tubing repairs have become a viable alternative to RWO's, which can easily exceed 1 million dollars. Repair methods include tubing straddles and coiled tubing packer repairs. The advantage over a conventional RWO is that there is no need to pull tubing, resulting in the well being returned to service faster. However, the main limitation for non-rig candidate selection has been in identifying leaks which are below the resolution of conventional leak detection methods. Often a well with annular communication had to be worked over because the leak point could not be determined. The ultrasonic leak detection tool has provided a step change in leak identification. Prior to its introduction, it was virtually impossible to detect leaks smaller than 1 gpm. Often the velocity and temperature changes associated with these leaks are below the resolution of conventional logging tools, including spinners, temperature logs, down-hole cameras, and noise logs. These tools are even more limited when trying to detect leaks that occur behind tubing. The ultrasonic leak detection tool can identify leaks so small as to be almost unbelievable. Tool Principles and Operation. SPE paper 1028151 details the tool physics and development history of the ultrasonic leak detection log. Tool principles are briefly summarized here. The frequency spectrum a leak produces is a function of differential pressure, leak magnitude, and leak geometry. These properties determine whether the frequency is audible, ultrasonic, or both. The ultrasonic logging tool (Figure 1) utilizes a sensor that detects a frequency spectrum, including those typically produced by leaks. The signal is processed by a series of band-pass algorithms that focus on frequencies in the ultrasonic range. Virtually all audible noise associated with tool movement is filtered out, allowing continuous logging. Typical logging speed is 30 feet per minute (fpm) and leaks can be identified while logging in either an up or down direction. Greater accuracy is achievable due to the characteristics of ultrasound, which attenuates, or dies away, quickly in fluids. Ultrasound typically travels only 3–10 ft in a wellbore before attenuating. This attenuation results in a very sharp leak character, typically identifying the leak within 1 to 2 feet.

No abstract

A common problem in oil and gas wells is excess free gas or water production from only certain portions of the completed interval. Other portions of the lower completion may still have viable oil or gas production potential if a method can be devised to successfully shut off the unwanted fluids. A coiled tubing deployed profile modification technique was developed primarily to shut off excess free gas production from the heel of cased and perforated horizontal oil wells. The technique has also been used for water and gas shut-off in both vertical and horizontal wells in a variety of lower completion types. The technique involves installing a temporary plug back to protect the toe or bottom most perforations to be preserved, then pumping a polymer gel followed immediately by a microfine cement to shut off the shallower or heel perforations. The objective of the gel and cement is to intentionally damage the rock matrix for a radius of~2 ft around the perforated intervals to be shut off, creating a zone of little or no permeability adjacent to the wellbore. If successfully executed, there is no cement to be milled out of the liner post squeeze and no restrictions or liner diameter reduction after the job. Approximately 30 horizontal wells have had a cumulative total of almost 13,000 ft of perforated intervals squeezed with this method. The technique has also been used to shut off liner corrosion leaks in horizontal wells and for perforation shut off in deviated wells. Post-job production logs in several of the wells indicated little or no flow from the squeezed intervals even 1 to 2 years after the job.