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Hydrates have been a major problem in natural gas industry for a long time. Gas hydrates are crystalline, ice-like compounds composed of water and natural gas. Formation of hydrates is highly undesirable as they block transmission lines, plug blowout preventers, jeopardize the foundation of deep water platforms and pipelines, cause tubing and casing collapses. The results can range from flow reduction to equipment damage.
The conditions that tend to promote hydrate formation include the following:
ï‚§ Low temperature
ï‚§ High pressure
ï‚§ Presence of free water.
There are various methods by which hydrate formation can be prevented. Some of them have been listed below:
1. Adjusting the temperature and pressure until hydrate formation is not favored
2. Dehydrating a gas stream to prevent a free water phase
3. Inhibiting hydrate formation in the free water phase.
Estimation Of Hydrate Inhibitor Injection Rates:
MEG( Monoethylene glycol ) is used as hydrate inhibitor in D1/D3 fields. This project highlights the indecision regarding the MEG injection rate due to the amount of water produced from the well. By devising an indirect method to estimate water production, the level of uncertainties in measurement of water production rates by WGFM has been tried to be minimized. It has also been shown that with any variation in pressures and water production rates, the amount of MEG to be injected also varies.
In order to determine the MEG concentration in the slug reaching the OT, Hammer-Schmidt equation has been used which is given below -
dT = temperature depression, which can be calculated by using the Trekell-Campbell temperature displacement chart for hydrate formers applicable in the pressure ranges of 1000-6000 psia.
The expression gives us the concentration of rich MEG being collected at the OT. The rich MEG has to be processed at the regeneration unit to produce lean MEG. The rate at which this lean MEG can be injected for the purpose of hydrate inhibition can be calculated from the following relation:
m l = Lean MEG mass flow rate (lb/day)
mw = Mass flow rate of water (lb/day)
Xl = Lean MEG concentration (wt %)
Using these correlations we have estimated the optimum MEG injection rate based on the water production rates
Liquid Loading is a very prevalent and common problem in Gas Wells. It occurs when the velocity of gas flowing up the tubing is lesser than the "critical velocity". This results in accumulation of water at the bottom of the well, applying a backpressure on the formation, thereby reducing well productivity. Several correlations have been proposed to calculate the critical velocity of the gas depending on operating conditions like Pressure, Temperature, composition of the gas etc.
There are several deliquification techniques present such as reducing the tubing size, surface compression, artificial lift etc. Nodal Analysis can help us determine the effects of such deliquification techniques and select the best possible technique.
Thus, this report attempts to:
Identify the best possible correlation to estimate critical velocity in Kg D6 gas wells.
Using the production data available to conduct a Nodal Analysis to estimate whether or not wells are loading up
Suggest the most optimal deliquification technique.
Based on the data available we have calculated the critical velocity using various models like Turner's Model, Colemann Model and Nossier Model.
Selected the best model which gives the most conservative of all value in the KG-D6 gas wells and thus shall be used to predict critical gas flow rates.
Using the reservoir pressure, flowing bottom hole pressure and gas production data we can plotted the Inflow Performance curve.
Then Future IPR's are obtained by plotting flow rates against Bottom hole Pressure for different values of Reservoir Pressure.
Tubing Performance curve is plotted by determining the bottom hole pressure at various flow rates in the tubing. The intersection of the IPR and TPR is called the operating point.
Critical Flow Rates are obtained by using the Turner's Model for different values of Bottom hole Pressure.
Points of intersection of Turner flow rates with all IPR's are observed to determine whether the well is loading or not. If any point of intersection is positioned right of the operating point at that IPR, loading will occur at that reservoir Pressure.
It has been concluded that the most economical techniques in the case of D6 gas wells would be Surface compression or tubing replacement and only these shall be studied by Nodal Analysis.
November: Sand Control
Sand production from oil and gas reservoirs will occur when the stresses in the formation rock exceed the mechanical strength of the rock material. This can happen in both unconsolidated and clastic reservoirs due to a combination of: high drawdown, depletion, changes in near wellbore fluid composition and cyclic loading of the wellbore.
The need for sand control
Sand production can cause a variety of problems with numerous technical, operational, environmental and economic implications. For example, sand exclusion; be it remedial or preventative may be required to:
1. Ensure the integrity of the production system and minimize facility downtime resulting from equipment failures (e.g. artificial lift).
2. Avoid sand failure which may lead to:
-down hole communication,
- buckling or collapse of production casing with the possible loss of the well.
Initially to select the appropriate sand control technique we require data like porosity, permeability, sand grain size etc.
Porosity and permeability are calculated using core analysis in the laboratory.
The required production history, amount of sand produced is availed from the department.
In order to determine the sand grain size we use calculated permeability and porosity of the reservoir rock.
Now, using these porosity and permeability data we calculated the sand grain size using the graph co-relating porosity, permeability and sand grain size.
Now depending upon the production factors like flow rate, temperature profile etc and reservoir characteristics like porosity, permeability, grain size, depth etc we proposed sand control techniques.
Now, depending upon the type of completion and also the target flow rate to be achieved we finally select our sand control technique.
Now using the permeability data and using the given co-relation we calculate the mean particle size
K = average permeability for a particular mean particle diameter (cm/s)
d = mean particle diameter of the soil sample (mm).
Reservoir souring is the phenomenon when there is an increase of mass of hydrogen sulfide (H2S) per unit mass of total produced fluids due to activities of sulphate reducing bacteria (SRB) as a result of waterflood.
In oil and gas exploration and production operations worldwide, injecting water into a reservoir to provide pressure support and sweep efficiency is essential to maximize economic levels of oil recovery. If the bacterial activity associated with water injection is not controlled, hydrogen sulphide (H2S) isÂ generated whichÂ ultimately 'sours' the reservoir and the oil and gas produced. Hydrogen sulfide is extremely toxic and corrosive and there is H2S level requirement in the sales gas (<4ppm).
Microbial reservoir souring can decrease the value of the oil and gas asset, increase operational costs and, in the worst case scenario; result in shut-in of the well due to materials incompatibility. Sweet low sulphur reservoirs can be soured by the activity of sulphate-reducing bacteria present in the reservoir, or introduced via the injection water (such as sea water, aquifer water, produced water).
The phenomenon of unexpected increase in hydrogen sulphide concentrations in produced fluids from petroleum reservoirs has been observed in different parts of the globe. In recent years at least two major North Sea oil fields are reported to have recorded higher concentrations of hydrogen sulphide in produced fluids after seawater breakthrough occurred. Conversely there are still several fields with mature water floods that have suffered few souring problems.
Zinc and iron based absorbers are cheap and react quickly, but can cause downstream oil/water separation problems. Aldehydes are cheap but slow reacting; a key point when this must take place between wellhead and separators. Strong oxidisers, like chlorine dioxide, have found preference since they are both quick in reaction and cause little production upsets. However, they are corrosive and require special metallurgies. New organic scavengers have been developed with some success but still requiring further improvements. Currently, triazine scavengers offer the highest efficiency and are building some track record of cost and performance.
Biocide treatments of injection wells have been tried to treat reservoir souring with little success. Failure has been attributed to the biocide not penetrating sufficiently deeply into the reservoir. Chlorine (at a residual level of > 10ppm) has been shown in sand packs to limit bacterial activity close to the inlet, but this could have severe consequences on corrosion in injecting wells.
Nitrate treatments change the bacterial population by encouraging nitrate reducing bacteria to use up all the available electron donors, preventing SRB's from using them.
Sulphate Removal from Injection Water
Reverse Osmosis plants are used to reduce sulphate levels in seawater used for injection developments. These were built for scale control, but could have some impact on potential souring. No work has yet been undertaken as far as we know, to establish whether such technology, which has enormous up front capital costs, could be effective in limiting reservoir souring by reducing the availability of the prime sources of SRB energy