Su!"mary. The ~ariati~n ~twee~ thickening-time test results from tests on pilot blends and cement-blend sample tests has been a subject of frequent InvestigatIOn. DIsagreement between these test results is often blamed on improper additive proportioning inadequate blending, or incorrect sampling techniques.' A comprehensive study of blending, sampling, and testing variables was conducted. This paper describes the results ,)f this research testing with a full-scale laboratory bulk plant. It also includes the results of a south Texas field study in which thickening time test results from more than 300 cement-blend samples were examined. Results of these studies suggest that significant statistical variations may be in~o~ved i.n ble~din¥, sampling, and ~esting pr~u.r~~ under deep-well conditions. The variabilities are used as guidelines for determInIng thlckerung-ttme acceptance WIndows. Vanabillttes or uncertainties can be minimized by optimization and standardization of these procedures. Re.ult. of Full·Scale Laboratory Blending and Sampling StudyCement-blend uniformity tested after even-numbered pneumatic transfers indicated that a minimum of four moves was required for adequate blending. 20 Cement-Blend Composition Class H cement, 3% (BWOW*) KCI, 0.2% low-temperature retarder Class H cement, 35% silica flour, 20% hematite, 3% KCI, 0.75% dispersant, 0.5 0 AJ fluid-loss additive Class H cement, 35 0 AJ silica flour, 70 0 AJ hematite, 13 0 AJ (BWOW) NaCI, 1.0% dispersant, 0.7 0 AJ fluid-loss additive, 0.25 0 AJ defoamer Class H cement, 3 0 AJ KCI, 0.15 0 AJ low-temperature retarder Class H cement, 35 0 AJ coarse silica, 27 0 AJ hematite, 0.5 0 AJ dispersant, 0.40AJ fluid-loss additive Class H cement, 35 0 AJ silica flour, 320AJ. hematite, 37 0 AJ NaCI, 0.9% low-temperature retarder, 0.25 0 AJ defoamer Class H cement, 35 0 AJ silica flour, 32 0 AJ hematite, 13 0 AJ NaCI, 0.2% dispersant, 0.8 0 AJ fluid-loss additive, 0.25% defoamer Class H cement, 35 0 AJ coarse silica, 46 0 AJ hematite, 0.75 0 AJ dispersant, 1.3% high-temperature retarder Class H cement, 35 0 AJ silica flour, 56 0 AJ hematite, 13% NaCI, 1.0 0 AJ dispersant, 0.7 0 AJ fluid-loss additive, 0.25 0 AJ defoamer Class H cement, 35 0 AJ silica flour, 3 0 AJ KCI, 0.25 0 AJ dispersant, 1.0 0 AJ fluid-loss additive Class H cement, 35% silica flour, 32 0 AJ hematite, 13% NaCI, 0.20AJ dispersant, 1.0 0 AJ fluid-loss additive, 0.20AJ high-temperature retarder, 0.25 0 AJ defoamer Class H cement, 35 0 AJ silica flour, 70% hematite, 13 0 AJ NaCI, 1.0 0 AJ dispersant, 0.7 0 AJ fluid-loss additive, 0.25 0 AJ defoamer Class H cement, 35% silica flour, 70 0 AJ hematite, 13% NaCI, 1.5 0 AJ dispersant, 0.7% fluid-loss additive, 0.25 0 AJ. defoamer Class H cement, 35% coarse silica, 8 0 AJ hematite, 13 0 AJ NaCI, 0.20AJ dispersant, 0.7 0 AJ fluid-loss additive, 0.20AJ high-temperature retarder, 0.25 0 AJ defoamer Class H cement, 35 0 AJ silica flour, 84 0 AJ hematite, 13% NaCI, 1.0% dispersant, 0.7 0 AJ fluid-loss additIve, 0.25% defoamer Class H cement, 85 0 AJ silica fl...

Recent research investigating causes and control of annular gas flow has resulted in new concepts pertaining to gas migration. Previous investigations have identified that the combined effects of fluid loss volume reductions and static gel strength development control the actual pressure loss - and ultimately gas flow - in a cement column. The recently developed concept describes delayed development of cement gel strength as a means of preventing gas flow. Delaying gel strength development allows the cement column to transmit essentially full hydrostatic pressure, and thus prevent gas entry into the cement column, for an extended time period. Test results are presented showing that fluid loss rate decreases with time so that most volume losses due to fluid loss occur during the delayed gel strength period. Thus, stringent slurry fluid loss requirements for probable gas flow situations may be relaxed. The conclusion of the delayed gel strength phase is followed by rapid progression to the set state thus helping prevent gas entry into a cement column. Another feature of delayed gel strength development, shutdown safety factor, is also presented. Pumping of delayed gel strength cements can be restarted without excessive horsepower or pressure requirements in the event of a shutdown during placement. Subject paper presents laboratory test results and field case histories documenting use of delayed gel strength cement for prevention of gas migration. Introduction A cementing method has recently been developed which utilizes delayed gel strength technology for annular gas migration control. By delaying cement gelation until the time after the majority of fluid loss volume reductions occur, the cement column is able to adjust to volume losses to maintain hydrostatic pressure transmission. Standard cements develop enough static gel strength to restrict the cement column's capability to provide this hydrostatic pressure maintenance function. When accompanied by fluid loss volume reductions even with low fluid loss cements — hydrostatic pressure may drop dramatically. If hydrostatic pressure drops enough to lose the confining overburden pressure on high pressure zones, annular flow will occur. Gel strength can be utilized beneficially, however, to prevent gas entry provided it develops rapidly enough to a level (500 lb/100 ft2) which will not permit gas percolation before overburden pressure is lost. An examination of the equations which predict cement column pressure losses will explain (1) the operating principles which govern the manner in which delayed gel strength development controls maintains hydrostatic pressure in a cement column and (2) how this physical property is used to help control annular gas migration. Laboratory and field data are presented to document the validity of approach to gas migration control. BACKGROUND AND THEORY Extensive research has been conducted into factors which give rise to annular gas migration. More than 25 papers related to this subject have been presented within the past 20 years. Several papers have documented pressure loss under laboratory test conditions. P. 43^

In many oil, gas, and injection wells. a string of tubing, sealed at itslower end in a packer, is used to isolate tubing pressures and fluids from thecasing. In multiple completions, two or more tubing strings are used to isolatezones. This paper presents a means of determining the best way to initiallyland the tubing in the packer to compensate for future anticipated wellconditions. The equations in this paper were developed in a previous publication andhave been successfully applied to over fifty critical wells in the UnitedStates, Canada, and Europe. Many of these were deep, high-pressure, high-temperature, high-cost wells in which it was imperative that atubing-to-packer seal be maintained during all completion, remedial. andproducing operations. In some of these wells, it was important to keep thetubing as straight as possible to facilitate future wire line work. The conditions of these wells have been grouped and tabulated so the readercan see some of the practical applications of the paper. Introduction The bottom of a string of unanchored tubing in a rod-pumped well moves up onthe upstroke and down on the downstroke. In addition, the tubing graduallyelongates until the well reaches pumping equilibrium. Disregardingrod-to-tubing friction, vertical movement is caused by pressure and temperaturechanges acting on the entire tubing string. Knowing tubing and casing size, initial and final fluid densities and levels, and initial and final tubingtemperature, it is possible to calculate the extent of these verticalmovements. Rod-pumped wells are generally familiar to the reader and are mentioned herebecause the freely hanging tubing string reacts in exactly the same manner tochanges in well conditions as does a string of tubing sealed, at its lower end, in a packer which permits free seal movement. A packer, however, may be setmuch deeper than a pump, and not only is a longer string of tubing exposed tothese changes but the changes may also be much more severe. Consequently, theamount of vertical movement is usually much greater.

The current state of the energy industry finds both operating and service companies squeezed by lower prices and higher costs. Investment in exploration, equipment, and technology has been severely restricted. Many operators are responding to these harsh market conditions by re-engineering their work processes and focusing on core business activities. Re-engineered work processes encourage operators and service companies to work closely together. This motivates both to eliminate duplication, simplify processes, increase efficiency and capitalize on combined expertise to enhance production and optimize total system cost. Alliances and partnering are based on mutual trust and the commitment to add value to both organizations. Aligning interests is fundamental in establishing a lasting and mutually beneficial relationship. This paper presents an overview of these new relationships. The benefits and concerns of changing from traditional bidding agreements to new business arrangements between producing companies and service companies is discussed. Evaluation criteria for potential candidates, how to structure an alliance or partnering agreement, and a discussion of the key issues in the application of incentive contracts is presented. Introduction As oil fields mature, the cost of producing a barrel of oil is increasing. New discoveries are getting costlier, while real crude oil prices have declined (see Figure 1). Petroleum Industry Profit Margins (Figure 2) are decreasing and remaining flat. These facts necessitate a different business approach for both operating and service companies. P. 199