Injection well operations

Groundwater quality at most refinery and terminal facilities is not pristine. Elevated concentrations of iron, manganese, BTEX, and petroleum hydrocarbons exist. Upon exposure to the atmosphere or air mixing, changes begin to occur in the makeup of the coproduced groundwater. Iron will precipitate out and form a scale on the 

FIGURE 8.8 Schematic showing recommended injection well design screening the vadose 

An important factor to keep in mind when designing reinjection wells or systems is that eventually they will have to be redeveloped. Reinjection wells and the redevelopment of these wells unfortunately follow the law of diminishing returns. Constant reinjection of coproduced groundwater without regular development results in irreversible clogging and ultimately the abandonment of the well. 

The location of the reinjection wells with respect to the recovery well is also an important consideration. Locating the wells too closely can create counterproductive effects. Locating the reinjection wells too far away from the recovery well may significantly reduce the desired effect or eliminate the benefits altogether. If the latter is the case, dead spots may result and may cause short-circuiting of the LNAPL pool hydrocarbon plume. Once this happens, off-site migration of the plume is possible. In fact, reinjection wells placed and spaced improperly can, in some instances, accelerate off-site migration. 

Reinjection wells are not without disadvantages. One disadvantage referred to above is the possibility of accelerating off-site migration or dispersion of the pool. Another disadvantage is the additional costs for operation and maintenance (i.e., redevelopment). Redevelopment costs can be kept to a minimum by initial design considerations, but, as the time frame between redevelopment decreases, redevelopment costs increase. Eventually the cost of constructing a new reinjection well becomes the only cost-effective alternative. 

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The bottomhole pressure of injection wells was determined according to the known barometric formula. However, for the gas wells a correction was made for the increase in gas density. The steam density was calculated to be 20-30% higher on account of the moisture content, and gas density was assumed to equal 0.7 of air density. Inasmuch as the pressure changes in the production-observation wells were not significant, the effects that the injection wells exerted mutually among themselves could be ignored. In other words, it was assumed that all injection wells operated independently of one another. Before the pressure field map was constructed, all pressures measured in the production-observation wells were brought up to the moment at which steam injection was discontinued. Visual extrapolation was used for that puipose. 

Further recommendations have been developed and may be incorporated into the detailed operating procedures to enhance supercritical carbon dioxide injection wells operational safety. 

R. F. Scheuerman and B. M. Bergersen. Injection water salinity, formation pretreatment, and well operations fluid selection guidelines. In Proceedings Volume, pages 33-49. SPE Oilfield Chem Int Symp (Houston, TX, 2/8-2/10), 1989. 

The term well plugging refers to any of a variety of processes that reduce the permeability of the injection formation or the screens that are placed in the well s injection interval. When permeability is reduced, injection rates must be reduced or injection pressures increased. Table 20.15 lists a number of ways in which plugging may occur. One or more of these situations will probably take place in most injection wells the number and severity of reactions will determine whether serious operational problems arise. If plugging is confined to the immediate vicinity of the injection well,... 

A full-scale cleanup was performed using in situ bioremediation to treat MTBE and BTEX at a service station in Massachusetts. Soil at the site consists of a layer of sand and gravel underlain by peat, silt, and clay. The in situ bioremediation system consisted of 12 injection wells and two butane injection panels used to stimulate cometabolic aerobic biodegradation of the contaminants in groundwater. The system was operated between October 2000 and January 2001. MTBE concentrations were reduced from 370 to 12 pg/L and BTEX contamination in groundwater was reduced by approximately two orders of magnitude during the 4-month period.74... 

The in situ bioremediation application at this site included injection of a liquid microbial solution into the subsurface through monitoring and injection wells. This solution includes microbes (Pseudomonas, Bacillus, and Corynebacterium), oxygen, emulsifier, surfactant, and nutrients. Five injections were conducted. Over 11.3 m3 (3000 gallons) was injected from February 1999 to September 2000 into approximately 40 wells and 15 Geoprobe injection points. As of September 2000, MTBE levels decreased by 96% (3310-146 pg/L), while benzene decreased by 83% (2571— 435 pg/L), toluene by 66% (24,330-8300 pg/L), and naphthalene by 84% (5377-853 pg/L) xylene levels increased and were above preoperational level as of September 2000. The system will continue to be operated until all target levels have been met. The total cost for the cleanup of this site is USD63,500.34... 

More recently well treatments that do not interrupt normal water injection operations have increased in frequency. Addition of surfactant to the injection water (144,146) can displace the oil remaining near the production well. The lower oil saturation results in an increase in the water relative permeability (145). Consequently a greater water injection rate may be maintained at a given injection pressure or a lower injection pressure. Thus smaller and cheaper injection pumps may be used to maintain a given injection rate. While the concentration of surfactant in the injection water is relatively high, the total amount of surfactant used is not great since it is necessary only to displace the oil from a 6-10 foot radius around the injection well. 

PILOT DESCRIPTION. The site of the TFSA-water flood pilot was chosen on the basis of four criteria the site was representative of reservoir conditions and production operations in the Main Zone, extensive historical production data was available for each of the production wells in the pattern, production wells completely surrounded the injection well, and the pattern appeared to be well isolated from adjacent patterns and injection wells. 

Some injected wastes are persistent health hazards that need to be isolated from the biosphere indefinitely. For this reason, and because of the environmental and operational problems posed by loss of permeability or formation caving, well operators seek to avoid deterioration of the formation accepting the wastes and its confining layers. When wastes are injected, they are commonly far from chemical equilibrium with the minerals in the formation and, therefore, can be expected to react extensively with them (Boulding, 1990). The potential for subsurface damage by chemical reaction, nonetheless, has seldom been considered in the design of injection wells. 

According to the Illinois Environmental Protection Agency (IEPA), a series of gas blowouts has occurred at two waste injection wells in the state (Brower el al., 1989). In each case, well operators were injecting concentrated hydrochloric acid into a dolomite bed. At its plant near Tuscola, the Cabot Corporation injects acid waste from the production of fumed silica into the Cambrian Eminence and Potosi Formations below 5 000 ft (1 500 m) depth. Allied Chemical Corporation injects acid into the Potosi formation below about 3 600 ft (1 100 m). The acid, which is contaminated with arsenic, is a byproduct of the manufacture of refrigerant gas. Since some of the blowouts have caused damage such as fish kills, there is environmental interest as well as operational concern in preventing such accidents. 

In efforts to increase and extend production from oil and gas fields, as well as to keep wells operational, petroleum engineers pump a wide variety of fluids into the subsurface. Fluids are injected into petroleum reservoirs for a number of purposes, including ... 

The injection of produced water and other oil held fluids into wells started as early as 1928. In 1976, more than 300 industrial waste disposal sites were in operation throughout the country. By 1986, approximately 60 million barrels of oil held fluids were injected through 166,000 injection wells within the conterminous United States. These volumes are anticipated to increase significantly in the future as producing helds continue to be depleted. Thus, construction requirements as listed in 40 CFR 146.22 are an essential prerequisite to the safe disposal/injechon of fluids and the prevention of contamination of USDW. 

Long-term operation monitoring may be performed to evaluate the potential for injection well fouhng, pH changes, and temperature variations and to identify unexpected variables. 

Control of site equipment is always important for safety and operational concerns. Many sites are remote or not staffed on a daily basis. Remediation equipment should be fitted with failsafe systems to shut down the system in the event of failure, fire, or unusual conditions (such as injection well plugging). Alarm systems should be included, which may be as simple as illuminating a warning hght, or as complex as a teleconnection to a remote computer station or telephone alert to the operator s residence. Many commercial companies offer remote monitoring equipment. 

Traditionally air sparging has been used as a groundwater remediation tool. Occasionally, however, it has been successfully used to remediate the vadose zone. In this application, the compressed air is injected through a well screen that is open to the VOC-contaminated area. The injection wells may be either vertical or horizontal (Figure 10.7). In this setting, the injected air is usually captured by a corresponding set of SVE wells (Figure 10.8). Properly spaced patterns of injection and recovery wells are necessary for efficient operation. 

Maintenance of current commercial status quo. At a few locations, the decision has been made to continue operation of the facility without disruption, so long as NAPL product and dissolved chemicals do not exit the boundary of the facility or provide a risk to workers or the environment at the site. Hydraulic containment of the aquifer is the procedure that is usually selected for these sites. A system including recovery wells and injection wells can often be operated to balance the subsurface flux so that product loss equals product recovery at a minimal cost. 

The injection well system has been expanded in conjunction with the operation of the recovery system. As a result of operational constraints and locations of injection wells in service, injection rates and volumes have varied. As of January... 

Successful operation of an injection well relies on the prediction of the direction and rate of concentrate flow, the displacement of pre-existing water, and the aquifer pressure change over time can be estimated. A knowledge of the subsurface hydrodynamics is therefore required to assist in these predictions (Shammas et al. 2009). 

Operating costs for injection wells are significantly lower when compared to capital costs. They include labour for operation and maintenance, chemicals for pretreatment, and power for pump operation (Mickley 2006). During operation of the well, the power required for pumping is the most significant cost (Mickley 2006). 

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