Shut-in time

Zirconyl chloride can be used to stabilize swelling clays in both acidic environments and in the presence of 600 F steam (160). No well shut-in time is required for polymerization to occur so zirconyl chloride may be used in conjunction with hydraulic fracturing treatments (161). 

Determination of gelation rate or set-time for a given composition is a parameter of utmost importance to the success of a treatment. Premature setting of the gel will result in failure of the treatment and could be very expensive. Delay of gelation, on the other hand, could also be costly due to the need for additional shut-in time. A host of methods ranging from visual observation " to various physical measurements have been applied for laboratory evaluation of bulk gels ". These include time of flight... 

Sometimes a short batch is forced down with a nitrogen displacement or compressed gas to speed up the fall rate and reduce shut-in time. An inhibitor squeeze is sometimes used to try to get a longer return time and simulate a continuous treatment. However, there is always the concern of formation damage with squeezes and with tubing displacements. 

HF shut-in time should be minimized to reduce repredpitation of reaction products. One should be skeptical ofHF treatments thatreqube an intentional shut-in period as part of the procedure, even in high-permeability formations. If HF shut-in is to exceed one day, the overflush should be designed to displace spent HF three to five feet from the wellbore. 

Unnecessary shut-in time can lead to reprecipitation of acid reaction products near enough to the wellbore to cause radial permeability damage. This is espedally true in cases in which acid was not or could not be displaced far away from the wellbore. Generally, intentional shut-in periods in sandstone acidizing treatments are questionable. 

In high permeability reservoirs, wells may produce dry oil for a limited time following a shut-in period, during which gravity forces have segregated oil and water near the wellbore. In fields with more production potential than production capacity, wells can be alternately produced and shut in (intermittentproduction) to reduce the field water cut. This may still be an attractive option at reduced rates very late in field life, if redundant facilities can be decommissioned to reduce operating costs. 

The failure rates and times-to-restore developed used a variety of data sources and data construction methodologies and are presented in Section 2. The principal methodology used is a kind of failure mode analysis for each component several principle modes of failure are analyed by characteristics including frequency of occurence, repair time, start-up time, and shut-down time. From these an average failure rate is developed and expressed as failures per million hours and mean time between failure(MTBF). 

Automobile companies are major users of just-in-time methods, coordinating the delivery of thousands of parts from many different suppliers. A transportation delay of a few hours for one part could shut down an assembly line for half a day. 

Upon shutting in the well, the pressure builds up both on the drillpipe and casing sides. The rate of pressure buildup and time required for stabilization depend upon formation fluid type, formation properties, initial differential pressure and drilling fluid properties. In Ref. [143] technique is provided for determining the shut-in pressures if the drillpipe pressure is recorded as a function of time. Here we assume that after a relatively short time the conditions are stabilized. At this time we record the shut-in drillpipe pressure (SIDPP) and the shut-in casing pressure (SICP). A small difference between their pressures indicates liquid kick (oil, saltwater) while a large difference is evidence of gas influx. This is true for the same kick size (pit gain). 

Step 1. The well is circulated at half the normal pump speed while keeping the drillpipe pressure constant (see Figure 4-352a). This is accomplished by adjusting the choke on the mud line so that the bottomhole pressure is constant and above the formation fluid pressure. To maintain a constant bottomhole pressure the formation fluid is allowed to expand, which usually results in a noticeable increase in casing pressure. This step is completed when the formation fluid is out of the hole. At this time casing pressure should be equal to the initial SIDPP if the well could be shut in. 

It is common in many offshore areas to encounter a shallow gas hazard. Quite often, these hazards can be spotted on seismic, and a surface location is chosen to avoid the hazard. However, there is always a risk of encountering a shallow gas flow with insufficient casing in the well to allow a shut-in. In this instance a diverter system is called on as a safety measure. The ideal function of the diverter system is to allow the well to flow and subside by natural means. In many cases the diverter system simply provides enough time to evacuate the rig. 

As discussed, modelled and simulated by Prenosil (1976), the dynamics of the process bring in the question of steam consumption, steam flow rate, starting time of the distillation, and shut-down time when the desired degree of separation has been reached. The modelling of steam distillation often involves the following assumptions. 

The cement slurry is pumped down the casing and up the annular space between the casing and the formation. The spacer and drilling fluid are thus displaced by the cement slurry. A compatible fluid (one that does not substantially alter the set time of the cement slurry) is pumped into the wellbore to displace nearly all the cement slurry into the annular space between the casing and the formation. The well is then shut in to allow the cement to set. This bonds the casing to the formation and isolates oil- and gas-bearing formations from aquifers and brine-containing formations. Fluid communication between formations can adversely affect production operations or lead to contamination of potable water aquifers. 

The initial charge to the reactor is 950 kg and 90% of this is converted in an isothermal batch time of 3.20 h. If the shut-down time between... 

Thus 1 m3 of reactor volume produces 1.26 kmol of ethyl acetate (molecular weight 88) in a total batch time of 6720 s, i.e. in 4920 s reaction time and 1800 shut-down time. This is an average production rate of ... 

For most reactions, the rate decreases as the reaction proceeds (important exceptions being a number of biological reactions which are autocatalytic). For a reaction with no volume change, the rate is represented by the slope of the curve of X (moles converted per unit volume) versus time (Fig. 1.10), which decreases steadily with increasing time. The maximum reaction rate occurs at zero time, and, if our sole concern were to obtain maximum output from the reactor and the shutdown time were zero, it appears that the best course would be to discharge the reactor after only a short reaction time tr, and refill with fresh reactants. It would then be necessary, of course, to separate a large amount of reactant from a small amount of product. However, if the shut-down time is appreciable and has a value ts then as we have seen in the example on ethyl acetate above, the average production rate per unit volume is ... 

Flo. 1.10. Maximum production rate in a batch reactor with a shut-down time ts... 

The penalties comprising the unit hazard factor are calculated based on a single, specific instant in time during which the material represented by the MF is associated with the process unit in the most hazardous state of operation. Start up, general operation, and shut down are among the operational states that should be considered. 

Forty-six case studies of hydrate plug formation and remediation are recorded in Hydrate Engineering (Sloan, 2000). In every case, hydrate plugs were remediated. In addition, a rule of thumb is that most of the offshore flowline shut-ins are less than the 10 h no touch time, which requires no antihydrate operation before restart (J.E. Chitwood, Personal Communication, August 1, 2003). However, hydrate prevention methods are very expensive, as shown in the above Canyon Express and Ormen Lange examples, or in the fact that deepwater insulation costs are typically U.S.Sl million per kilometer of flowline. 

Their poison stayed shut in. traffic had been playing something German from Mr Hyde. Hollow, metallic, funky. Billy wanted to put on Sasha and Digweed. An argument reignited by the time she was... 

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