North America

Matrix acidizing treatments containing hydrogen fluoride (HF) acid have been utilized in stimulation treatments of offshore wells to remove skin associated with fines migration for many years. In the last few years, operators have moved toward the use of organic acid - HF acid treatments due to corrosion concerns in the downhole tubular strings during the initial pumping of live acid and in the Titanium Stress Joints (TSJ) during the acid flow back through the production riser. A corrosion inhibitor to inhibit any unspent HF in the acid flowback returns would be beneficial to operators. Production of spent acid flowing back through the production riser is seriously being considered because significant cost savings may be realized over other acid flowback options. However, although most HF acid systems are mostly and/or highly spent during the reaction time with the formation mineralogy, even small concentrations of remaining free HF in the spent acid returns can result in severe bore surface corrosion (etching) and byproduct hydrogen absorption by the riser system TSJ. Lab studies were performed with several different inhibitor formulations added to two different spent organic - HF acid fluid systems to determine the ability for these candidate inhibitors to thwart corrosion (etching) and corresponding hydrogen uptake on ASTM Grade 29 titanium (Ti-29) test coupons. These candidate inhibitors were subjected to four-hour exposure tests conducted at 170 F under 3500 psi pressure with various inhibitor concentrations to determine if the package could meet screening criteria of corrosion/etch rate of less than 0.5 mils per day (0.5 thousandths of an inch) and hydrogen uptake limits consistent with ASTM product specification limits for the short term exposure (i.e., four hours). These lab test results are compared to those from recent published lab test studies on titanium in live and spent HF containing acid fluids, along with discussion on practical implications and considerations for their field use. Developing a corrosion inhibitor to inhibit the residual HF acid in the spent flowback returns and prevent etching and hydrogen uptake by the TSJ in the production risers not only yields effective protection of the TSJ, allowing flowback fluids to be returned thru the production riser, but also offers a significant operational cost savings.

A multi-phase stimulation treatment was required and subsequently executed in deep-water Gulf of Mexico to remediate a multitude of damage mechanisms resulting from years of hydrocarbon production. Among the many challenges that deep-water operators must face, there is the need for remediation of wells experiencing a decline in production. The execution of these treatments can prove to be very costly and require extensive damage assessments to properly design the most effective stimulation plan. Treatment placement is a major part of the decision process and will impact the performance of the job. A well in the Mississippi Canyon field had an asphaltene deposition issue based on asphaltene onset pressure evaluations as well as suspected fines migration issues. Each requiring its own treatment protocol. This operation required that a rig be moved onto location so that the job could be pumped via coiled tubing to assure injectivity into the zone of interest.

A multiphase approach design included:

Phase I -a screen/near wellbore soak

Phase II- a diverted specialty solvent formation treatment to remediate asphaltene deposition.

Phase III- a diverted mud acid treatment that included specialty stimulation systems to address scaling, clay and fines issues.

The challenge is the difference between utilizing xylene alone for organic deposition removal verses specialty solvent treatments specific to asphaltene removal as well as the use of deep penetrating hydrofluoric acid blends and specialty additive packages.

Utilizing this multi-phase approach resulted in a successful treatment outcome for the operator. An increase in total fluids production, an increase in flowing tubing and a job pay off of less than 30 days was the result of finding a solution to these particular set of challenges.

The paper will include an introduction of dissolvable plug and its development in oil & gas upstream business. Dissolvable plug is a customized tool, and it could be modified by controlling its chemical compound to adjust its dissolving rate. In addition, slim version dissolvable plug is a plug solution with dissolvability originally brought out to overcome the downhole restriction challenge (ID of SSD), namely to pass the downhole restriction then to set in the original casing ID. A case study of its application in offshore squeeze cementing job will be analyzed in this paper, from the plug designing perspective to operational data recap to prove its benefits. Conventional plugs will leave the bottom of the plug body downhole after plugs slip losing integrity during the milling operation, and the remainder leaving downhole will choke the well production or even block the well, however, dissolvable plug remainders will dissolve itself downhole, which will not have an impact on the production.

In the last quarter-century, financial options such as "calls" and "puts" on publicly traded stocks have become an integral part of managing stock portfolios. The seminal work on financial options was done by Black and Scholes,[1] published in 1973, and Merton,[2] also published in 1973. Merton and Scholes shared the 1997 Nobel Prize in economics for their work. Black, Scholes, and Merton all worked on attempting to determine the value of an option. In recent years, the concepts of valuing options have been expanded from financial options to what are called "real" options in project evaluation.

Shale gas is becoming increasingly important globally. The nature of these reservoirs pose special considerations in reserves estimation. What follows was written in 2001 and needs to be updated based on current experience. Nonetheless, some of the considerations mentioned remain appropriate. As reported in mid-2000, natural gas produced from shale in the US has grown to be[1] approximately 1.6% (0.3 Tcf annually) of total gas production.

Discovered resources of heavy and extraheavy crude oil are estimated to be approximately 4,600 billion bbl, two-thirds of which are in Canada and Venezuela.[1] Bitumen and tar sands are excluded from this estimate. Published data on reserves estimates (RE) from this resource by primary drive mechanisms are sparse. Meyer and Mitchell[2] estimated worldwide ultimate recovery from heavy and extraheavy crude oils to be 476 billion bbl, which is 10% of the Briggs et al.[1] estimate of the discovered resource initially in place. Estimated primary reserves estimates (RE) ranges from 8 to 12% oil-in-place (OIP) for the Orinoco area of Venezuela, where stock-tank gravities range from 8 to 13 American Petroleum Institute (API).[3]

Heavy oil is defined as liquid petroleum of less than 20 API gravity or more than 200 cp viscosity at reservoir conditions. No explicit differentiation is made between heavy oil and oil sands (tar sands), although the criteria of less than 12 API gravity and greater than 10,000 cp are sometimes used to define oil sands.[1][2][3][4] Unconsolidated sandstones (UCSS) are sandstones (or sands) that possess no true tensile strength arising from grain-to-grain mineral cementation.

In-situ combustion processes are largely a function of oil composition and rock mineralogy. The extent and nature of the chemical reactions between crude oil and injected air, as well as the heat generated, depend on the oil-matrix system. Laboratory studies, using crude and matrix from a prospective in-situ combustion project, should be performed before designing any field operation. The chemical reactions associated with in-situ combustion are complex and numerous. They occur over a broad temperature range.

When product vapor pressure is greater than 0.5 psia (more in some states) but less than 11.1 psia, the U.S. Environmental Protection Agency permits the use of a floating-roof as the primary means of vapor control from the storage tank. Floating-roof tanks are not intended for all products. In general, they are not suitable for applications in which the products have not been stabilized (vapors removed). The goal with all floating-roof tanks is to provide safe, efficient storage of volatile products with minimum vapor loss to the environment. Design requirements for external floating roofs are provided in Appendix C of the API Standard 650.

Specially designed pressure/vacuum vent valves should be provided to protect the tank against overpressure or vacuum conditions. Safety should be a primary concern when selecting a storage tank vent system for a specific application. In production operations, this normally means that a safe way of handling vapors that evolve from the liquid must be designed into the system, and air must be excluded from entering the tank and mixing with hydrocarbon in the vapor space. Fixed-roof tanks should be configured to operate with a suitable gas blanketing system that maintains the tank at positive pressures under all operating conditions. Tank vent piping should include flame arrestors such as that shown in Figure 1, which protect the tank against ignition of the vent gases owing to lightning strike or a discharge of static electricity at the vent location.