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Operators in the Gulf of Bohai have practically eliminated remedial squeeze cementing requirements by using encapsulated air as a lightweight cement additive. Air entrapped in hollow beads composed mostly of silicon and aluminum is added to the slurry to allow for mixtures lighter than water, but with necessary strength to provide good primary cement jobs.
Cementing in the Gulf of Bohai is made difficult by bottom-hole static temperatures (BHST) of 275-320F (135-160C). Specific gravity of the mud is 1.1 to 1.3. Most wells have three to eight productive zones, making good isolation between zones productive zones, making good isolation between zones critical to drillstem testing and future production work. Use of high-strength microspheres (HSMS) as a cement additive has improved primary casing and liner cementing to the point that remedial squeeze cementing in the Gulf of Bohai is now a rarity.
Although cementing casing in oil and gas wells was a recommended practice as early as 1911, the advantages of using low-density cement slurries to achieve competent cement jobs were not recognized until the 1940's. Since that time, lightweight slurries have been used in wells that extend through weak formations that are sensitive to hydrostatic pressure exerted by the column of cement. These weak pressure exerted by the column of cement. These weak formations can be found worldwide, and have generated an increased demand for ultralow-density cement slurries.
To reduce cement density, materials such as bentonite, attapulgite, diatomaceous earth, fly ash, gilsonite, ground plastics, walnut shells, and silicate extenders have been used and accepted, subject to their limitations. Asphalt, oil emulsions, and low-strength microspheres have been tried, but not well accepted.
The primary goal of lightweight additives is to reduce slurry density while maintaining adequate strength. When using water-extending additives, a water/cement (w/c) ratio of 180% is needed for a slurry of 11 lbm/gal (1318 kg/m3). This water ratio is near the maximum that will create a slurry with useful compressive strength, except for filler cements where slow strength development is acceptable. To create a slurry of 10 lbm/gal (1198 kg/m3) would require a w/c ratio of 300%, which would result in a slurry without enough strength for any useful purpose.
Incorporation of HSMS into cement slurries is essentially using encapsulated air as a lightweight additive. Fig. 1 shows HSMS additive in its neat form; Fig. 2 shows hydrated cement containing HSMS additive. The high strength of the spheres will withstand the mechanical shear, frictional forces, and hydrostatic pressures encountered in placement of cement slurry into oil and gas wells. Addition of HSMS to slurries can reduce density to less than the mixing water alone, with strength sufficient for use over a wide range of pressures and temperatures. The ability of this admixture to reduce the density of a cement slurry results from a low particle density and relatively low water absorbency. The effective particle density of HSMS ranges from 5.25 lbm/gal (629 particle density of HSMS ranges from 5.25 lbm/gal (629 kg/m3) at atmospheric pressure to about 8.33 lbm/gal (998 kg/m3) at 6000 psi (41.37 MPa).
This predictable and limited density increase with increasing pressure is the characteristic that makes HSMS suitable for use in high pressure applications. Low water absorbency and low particle density result in greatly reduced w/c ratios compared to other low-density admixtures. As a result, strength development of 10 lbm/gal (1198 kg/m3) HSMS slurries will be about the same as that of 13 lbm/gal (1558 kg/m3) slurries prepared from other types of lightweight additives.
Lightweight slurries prepared with HSMS additive will generally develop higher 24 hour compressive strength than equivalent density slurries prepared with bentonite, gilsonite, or silicate extenders (Fig. 3). Fig. 4 shows yield of slurry per pound of HSMS additive used.
This paper was presented at the 56th Annual Fall Technical Conference and Exhibition of the Society of Petroleum Engineers of AIME, held in San Antonio, Texas, October 5-7, 1981. The material is subject to correction by the author. Permission to copy is restricted to an abstract of not more than 300 words. Write 6200 N. Central Expressway, Dallas, Texas 75206.
Results of a three-year study concerning the cementing of geothermal wells are reported. The U.S. Department of Energy (DOE) funded research included some specific tasks: (1) determination of properties an adequate geothermal well must possess; (2) properties an adequate geothermal well must possess; (2) thorough evaluation of current high-temperature oilwell cementing technology in a geothermal context; and (3) recommendation of specific cement systems suitable for use in a geothermal well.
At the present time, geothermal wells are completed in much the same manner as conventional oil wells; however, the environment with which completion materials must contend in a geothermal well can be much more severe. For example, the bottom-hole temperature in a geothermal well can be as high as 370 degrees C and the formation brines downhole we often extremely saline and corrosive. The failure of wells in several geothermal fields, has been directly attributed to degradation of the cement, implying that the cementing materials currently used to complete geothermal wells may not have been sufficiently evaluated. This paper describes a three-year research effort performed at Dowell to examine currently utilized cementing systems and to identify the best formulations for the completion of geothermal wells.
The project was divided into two major phases. Phase I was concerned with the definition of Phase I was concerned with the definition of requirements for geothermal cements, and the development of test procedures to simulate a geothermal environment. Phase II involved laboratory and site evaluation of candidate geothermal cement systems. Also involved in Phase II was a basic research program having to do with the chemistry of cements at the elevated temperatures commonly encountered in geothermal wells. Results of the basic research have been previously presented and will not be covered here. presented and will not be covered here. PHASE I PHASE I To better define the geothermal problem and to determine the properties a geothermal well cement must possess, several operators and engineers from various companies with geothermal drilling and completion expertise were interviewed. For reasons of confidentiality, the operators surveyed will not be identified here nor will the exact area in which they are currently doing business be revealed. This concession was necessary to obtain most of the information. The information gleaned from these interviews was extremely valuable in that several misconceptions concerning geothermal cementing were cleared up, and a more accurate and representative testing program could be designed and initiated. A summary of the most important findings is found in Table 1.
The survey results show that temperatures encountered during cementing operations rarely surpass 216 degrees C, and typically are in the vicinity of 115 degrees C. These temperatures are somewhat lower than what one would intuitively expect considering the bottomhole static temperatures encountered in most geothermal wells. The reported reservoir temperatures ranged from 200 degrees to 375 degrees C. In addition, most of the drilling/cementing programs of the companies interviewed call for setting programs of the companies interviewed call for setting of casing above the geothermal zone before the higher temperatures are actually encountered.
Rivera, N. N. (Chevron Thailand Exploration and Production, Ltd.) | Siritheerasas, K.. (Chevron Thailand Exploration and Production, Ltd.) | Valentino, V.. (Baker Hughes) | Fauchille, G.. (Baker Hughes) | Thein, A.. (Baker Hughes) | Stanley, R.. (Baker Hughes) | Brandl, A.. (Baker Hughes)
Abstract The Gulf of Thailand is characterized by shallow-water depth wells with bottomhole static temperature ranging from 240 to more than 420°F. These wells are drilled to an average of 12,000 ft MD and 9,000 ft TVD with a fast paced-batch drilling strategy. Most cement jobs are done offline, and on the surface section can be as frequent as 6 jobs per day. With multiple rigs, operators can require more than 100 cementing operations per month and cement volumes as high as 18,000 bbl. This efficient operations environment creates a demand for a logistically and operationally simple cement system that can be applied in all well sections and across the full range of expected temperatures. An advanced, lightweight seawater-based cementing concept was tested for this application. This new cementing system uses a single blend with only 3 to 4 primary liquid additives (including a stable, high-temperature, multi-functional polymer) to adjust all primary cement jobs for the entire wellbore. A sophisticated lab testing program was conducted for the innovative cementing concept according to the required demands on cement slurry design given the harsh wellbore conditions in the Gulf of Thailand. Tests revealed that the developed cementing systems meet all well requirements despite low densities of 13.3 to 14.0 ppg with high water content. This advanced cementing system was introduced in 2011 and has gradually been used on all wells since then – to date more than 500 wells in the Gulf of Thailand. In addition to improving logistics, use of the system has enhanced cement bond quality in production tubing cementing jobs. This improvement also reduced pay at risk due to insufficient cement isolation. This is evident in the whole range of well temperatures.
Brandl, Andreas (Baker Hughes) | Valentino, Vincentius (Baker Hughes) | Fauchille, Guillaume (Baker Hughes) | Syed, Haidher (Baker Hughes) | Dean, Greg (Baker Hughes) | Stanley, Rick (Baker Hughes) | Rivera, Nemboy Nemesio (Chevron Thailand Exploration & Production Ltd.)
The Gulf of Thailand is characterized by shallow-water wells that are hot and deviated, with low fracture gradients and bottomhole static temperatures of 450°F (and some wells approaching 520°F). Drilling depths average 12,000 ft measured depth (9,000 ft vertical) and fast drilling practices are used for slimhole monobore completions, resulting in daily cementing jobs from each of the offshore rigs. Many jobs are executed in batch mode and are performed offline on the production deck under the rig floor. As a consequence these fast-paced, streamlined, and simultaneous offshore activities require a high degree of rig integration as well as logistically and operationally simple high-performance cementing systems to avoid expensive rig delays. The performance demands on the cement slurries include low density, uncomplicated on-the-fly mixing, low fluid loss, gas invasion control, and stability under the very hot wellbore conditions. This paper will present an advanced lightweight seawater-based cementing concept using a single cement blend with only 3 to 4 primary liquid additives (including a multifunctional polymer) to adjust all primary cement jobs for the entire wellbore. A sophisticated lab testing program (such as analyzing slurry gas invasion) was conducted for the innovative cementing concept according to the required demands on cement slurry design and the given harsh wellbore conditions in the Gulf of Thailand. Tests revealed that the developed cementing systems meet all operator and well requirements despite their relative low densities of 13.3 to 14.0 ppg with high water content. The advanced lightweight cementing design was successfully pumped in 311 Thailand offshore wells during 2012, and its performance was directly compared to previous cementing systems used in more than 1,000 wells in the same fields from 2009 to 2012. Lab test results, pre-job planning, cement job execution and cement bond logs are evaluated and discussed. The case histories conclude that the advanced lightweight cement design significantly improved the quality of zonal isolation in wellbores. Valuable design-effect relationship elements found in this study (such as the impact of the multi-functional polymer on slurry stability and gas control) will be discussed for applications on other upcoming and challenging drilling projects in Asia.
American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract Neat Portland cement systems lose strength and become permeable at temperatures above 250 degrees F. This deterioration usually is more extreme over the first few days or month of heating but is usually not severe enough to cause disintegration of the neat cement. After this initial regression many neat Portland systems will regain a portion of Portland systems will regain a portion of their strength and reduce in permeability. This temperature regression of cement can largely be prevented by using about 35 per cent very fine silica sand. The strength can be maintained or increased but permeability will increase. Most additives for oil well cements can be included in such a silica stabilized system without extensive effect due to temperatures up to 600 degrees F. An exception to this is fly ashes and, to some degree, natural pozzolans. These are stable at 450 degrees but are losing strength and recrystalizing 600 degrees F. Introduction The deterioration of Neat Portland cement at temperatures above 250 degrees F (120 degrees C) has been known for many years. Menzel proved that fine silica added to a Portland cement paste would improve the strength of cements cured at elevated temperatures. An increasing number of wells are being subjected to these elevated temperatures each year. Deeper and hotter oil and gas wells are being drilled and other wells are being subjected to hot water, steam, or fire flood methods. High temperature geothermal wells are also increasing in number each year. The cement in these wells will be subjected to elevated temperatures from bottom to top. It is probable, therefore, that the surface and intermediate strings on many of these wells are not adequately protected from deterioration.