well completion & stimulation assigment

8/3/2019 Well Completion & Stimulation Assigment

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WELL BORE AND RESERVOIR PROBLEMS AFFECTING THE WELL PERFORMANCE:

Introduction:

The engineering work for sustaining and enhancing oil and gas production rates starts from identifying problems thatcause low production rates of wells, quick decline of the desirable production fluid, or rapid increase in the undesir-able fluids.

Following are the factors that put influences on wellbore and reservoir performances:

1) For oil wells, these problems include,

a) Low productivity

(Excessive gas production, Excessive water production or Sand Production)

2) For gas wells, the problems include:

a) Low productivityb) Excessive water production, Liquid loading

c) Sand production

Although sand production is easy to identify, well testing and production logging are frequently needed to identify the causes of other wellproblems.

A) Low Productivity:The lower than expected productivity of oil or gas well is found on the basis of comparison of the wells actual production rate andthe production rate that is predicted by Nodal analysis. If the reservoir inflow model used in the Nodal analysis is correct (which is oftenquestionable), the lower than expected well productivity can be attributed to one or more of the following reasons:

1) Overestimate of reservoir pressure

2) Overestimate of reservoir permeability (absolute and relative permeabilitys)3) Formation damage (mechanical and pseudo skins)4) Reservoir heterogeneity (faults, stratification, etc.)5) Completion ineffectiveness (limited entry, shallow per forations, low perforation density, etc.)6) Restrictions in wellbore (paraffin, asphalting, scale, gas hydrates, sand, etc.)

Note: The first five factors affect reservoir inflow performance, that is, deliverability of reservoir and can be evaluated on thebasis of pressure transient data analyses.

B) Excessive Water Production:

Excessive water production is usually from water zones, not from the connate water in the pay zone. Water enters the wellbore due tochanneling behind the casing (Fig. 15.14), preferential flow through high-permeability zones (Fig.1), water coning (Fig. 2), hydraulicfracturing into water zones, and casing leaks.

Figure1: Water production due to channeling behind the casing Figure 2: Preferential water flow throughhigh-permeability zone


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Figure:5 Gas production due to gas coning (Clark and Schultz, 1956)

D)Liquid Loading of Gas Wells:

Gas wells usually produce natural gas-carrying liquid water and/or condensate in the form of mist. As the gas flow velocity in the welldrops because of reservoir pres sure depletion, the carrying capacity of the gas decreases. When the gas velocity drops to a critical level,liquids begin to accumulate in the well and the well flow can undergo an annular flow regime followed by a slug flow regime. Theaccumulation of liquids (liquid loading) increases the bottom-hole pressure, which reduces gas production rate. A low gas production ratewill cause gas velocity to drop further. Eventually, the well will undergo a bubbly flow regime and cease producing

E) Sand Production:

The production of formation sand with oil and or gas from sandstone formation creates a number of potentially dangerous and costlyproblems. Losses in production an occur as result of sand partially fill up inside the wellbore if flow velocities cannot transmit theproduced sand on the surface; this may cause shut of production entirely.

Formation Damage is another problem is associated with both gas and oil wells that produced sand unchecked. The possible creation of

void space behind the casing can leave the casing and any shale streaks in the reservoir unsupported. Specifically, casing the casing is

subjected to heavy (compressive) load causing collapse or bulking. The much less permeable shaley streaks that remain can collapse

around the perforated casing causing sever irreparable restriction to production. Failure to prevent a casing from sand production at early

stage may cause devastating effect on tubing and casing in shape of corrosion.

Evaluation Technique Of Well Performance:

The well performance can be evaluated by Productivity index (P.I). Defined by symbol j. Productivity is the ratio of the total liquid flow

rate to the pressure drawdown. For water free oil Production, the productivity index is given by:

--------------1)

Where Q0= oil flow rate , STB/day

J= Productivity Index

Pwf= Bottom hole Pressure

P=draw Down, Psi

The Productivity index generally measured during a production of test on the well. The well is shut in until the static pressure pressure is

reached. Then well is allowed to produce at a constant flow rate of Pwf. Since a stabilized pressure at a surface does not necessarily

indicate a stabilized Pwf, the bottom hole flowing pressure should be recorded continuously from the above equation (1).

It is important to measure P.I when well is reached to Pseudo steady state, as shown in figure :


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Figure 6: P.I during Flow regimes.

Productivity index numerically can be find from :

-----------------2)The above equation is combined with Equation 1):

---------------3)The Kro (Oil relative Permeability) concept can conventionally introduced into Equation:

Since the most of the life well is spent in a flow regime that is approximately the pseudo state, the Productivity is a valuable methodology for

predicting the future performance of wells.

The Specific Productivity index can be calculated as:

------------4)Or

------------5)


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Figure:7 Q0 Vs P relationship

Alternatively Equation 1) can be further modified as:

----------6)

The above expression show that plot Pwf against Qo is straight line with a slope of (1/-J), as Show below figure:

Figure 8: Inflow Performance curve

Then AOFP can Calculated form:

--------7)

Hydraulic Fracture:

Many reservoirs must be hydraulically fractured to become economically productive. Hydraulic fracturing involves injecting alarge volume of proppant-laden fluid at a pressure sufficiently high to fracture the formation. After the fracturing fluid leaks off into the

formation, the remaining proppant keeps the fracture open. Although a hydraulic fracture is narrow (a fraction of an inch in most cases),the presence of this high-permeability channel significantly enhances the productivity of the well. The presence of a fracture alters the flow

regime inside the formation as the fluid flows into the fracture and then through the fracture into the wellbore, with very little or no fluid flowing

directly from the formation into the wellbore. The presence of a Hydraulic fracture adds another dimension to the fluid flow in porous

media and to well test design and analysis.

Three types of fractures have been presented in the literature: infinite conductivity, uniform flux, and finite conductivity. These fractures are

discussed below.


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1) Infinite-Conductivity Fracture:

In this case, the fracture permeability is significantly higher than the formation permeability, causing the pressure drop inside the fracture to be

negligible compared to the pressure drop in the formation. Practically, this situation is achieved when dimensionless fracture conductivity ishigher than 100.

As the presence of the infinite-conductivity fracture , fluid in the porous medium immediately surrounding the fracture and start to flow into the

fracture as soon as the well is put on production. Since the stream lines are perpendicular to the fracture face, the flow pattern during this early

time period is linear. The dimensionless pressure is given by the following equation:

---------8)

As more volume of the reservoir starts contributing to production, the flow pattern becomes elliptical. After a long time period, this elliptical flow

may be approximated by a radial flow pattern. This period is usually referred to as pseudo radial flow:

---------10)

Figure (9)is the log-log type curve of a well intersecting an infinite-conductivity fracture. The early-time period is a line with a slope

of one-half, indicating the presence of linear flow in the formation.

Figure 9): Type curve for a well intercepting an infinite-conductivity fracture

The fracture length may be calculated from the skin factor using:

-----------11)

2) Uniform-Flux Fracture:

In this case, it is assumed that the flow rate from the formation into the fracture is uniformly distributed across the fracture face. This solution

was initially used to approximate fluid flow in naturally fractured formations. The use of this model for that purpose has significantly declined in

recent years, in favor of the dual-porosity models. However, we have found that many of

the acidized, naturally fractured reservoirs tend to follow this model, especially reservoirs located in the Middle East.

As in the case of the infinite-conductivity fracture, the fracture length may be calculated from the skin factor. However, the equationis slightly different:

----------12)


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3) Finite-Conductivity Fracture:

It is more realistic to assume that a hydraulic fracture will have a finite conductivity. In this case, the pressure drop inside the fracture is notnegligible when compared to the total pressure drop in the system. The flow regime in a reservoir that has a finite-conductivity fracture is

significantly more complex than in the case of infinite-conductivity fractures.

The flow regimes experienced during producing or testing a finite-conductivity fracture are represented by:

Figure:10 Fracture flow regimes

At very early time, fluid inside the fracture expands and starts flowing towards the wellbore, forming an early linear flow inside the fracture. Thisperiod is controlled by both the conductivity and diffusivity of the fracture. This flow period will appear as a one-half slope, straight line on the

type curve for a fractured well. This flow period is at very early time, and it would

probably not be recorded or it would be masked by the presence of wellbore storage. Therefore, although this flow period may be of technical

interest, it does not have much significance from a practical point of view.

Fractures with Changing Conductivity:During the creation of a hydraulic fracture, the conductivity may vary from one place in the fracture to another. Several works have studied thiseffect (Bennet et al., 1983; Soliman, 1986a; Soliman et al., 1987). Using both analytical and numerical simulators, Soliman (1986b) showed the

choking effect of having low fracture conductivity near the wellbore as well as the

effect of using a tail-in of better proppant near the end of the fracturing treatment. It was concluded that the effect of fracture conductivity

distribution is more complex than was thought at the time. Soliman (1986b) has also calculated the optimum conductivity distribution inside the

fracture.

Figure: 11 Optimum conductivity distributions inside a hydraulic fracture


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This optimum conductivity distribution indicates that if conductivity within the fracture follows a certain distribution pattern, a fracture may

behave as if it had uniform conductivity equal to the one at the wellbore. Poulsen and Soliman (1987) presented a procedure to convert the curves

in Fig. 11 into an optimum proppant distribution, thereby producing an optimum fracture design. This procedure could lead to the use of less

proppant and to a lower chance of sand-out. At the same time, it does not compromise the performance of the designed fracture.

Effect of Low Fracture Conductivity:

As the fracture conductivity declines, the fracture becomes less efficient. Parts has studied this problem analytically, producing Fig. 12-12. Before

we discuss this figure, we need to define the conductivity term used by Parts:

-----------13)

and thus,

----------14)

well completion & stimulation assigment

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