CHAPTER ONE
1.0 INTRODUCTION
1.1 Background of Study
After
the completion of a given well or group of wells, they are then put under
production. During this phase of operation, every operator looks for means to
minimize operating cost and maximize cumulative oil production in the most
cost-effective manner for the entire field. This stage of operation is what is
generally termed production optimization. A true optimization requires an
operator to take a logical look at the field’s production systems from the
sub-surface to surface facilities.
Production
optimization implies striking a balance between production deliverability of
the wells and demand which basically aim at increasing the rate at which a well
flows fluid from the reservoir without restriction to the surface storage
tank(s). One of the most common means of conducting production optimization is
through nodal analysis. This is normally done to optimize production from
single wells or other smaller production systems. Large complex systems demand
a much more sophisticated approach to predict the response of a large
complicated production system accurately and to examine alternative operational
scenarios efficiently. Beggs (1991) stated that optimization is directly
dependent on some functions. The functions may be a single variable or more
than one variable (multivariate optimization). A well is said to be optimized
when it is producing at optimum conditions with minimum problems (Bath, 1998).
Most
wells upon completion in oil producing sand formations will flow naturally for
some period of time. Production at this stage will be initiated by the existing
reservoir pressure. This reservoir pressure will provide all the initial energy
needed to bring fluid from the well to the surface. As the well produces, this
energy is consumed and at some point, there will no longer be enough energy to
bring fluid to the surface. The well at this state, will cease to flow. When
this happens, there is need for the well to be put under some form of
artificial lift method in order to provide the energy needed to bring the fluid
to the surface. It should be pointed out that artificial lift systems can also
be used in de-watering of gas wells to sustain production.Basically, there are two
methods of artificial lift systems. These are: pumping system (electrical
submersible pump, sucker rod etc.) and Gas lift system.
There
are different key factors that are considered prior to artificial lift
installation in the field which include analysis of the individual well’s
parameters and the operational characteristics of the available lift systems.
For the different pumps and lift systems available to the oil and gas industry,
there are unique operational/engineering criteria particular to each system,
but they all require similar data to properly determine application feasibility.
Such as the inflow performance relationship, liquid production rate, Gas liquid
ratio, water cut, well depth, completion type, wellbore deviation, casing and
tubing sizes, power sources etc. Each of the artificial lift systems has
economic and operating limitations that rule out it consideration under certain
operating conditions.
An extensive overview of artificial lift design
considerations was presented by Clegg et al. (1993). Clegg mentioned some
economic factors such as: revenue, operational and investment costs as the
basis for artificial lift selection.Ayatollahi et al., (2001): Selection of the
proper artificial lift method is critical to the long-term profitability of the
oil well; a poor choice will lead to low production and high operating costs.For
the purpose of this work, Gaslift method will be considered with a view to
optimizing production from an oil well and hence optimal production from the
field.
1.1.1 Gaslift
system
Gaslift
is the method of artificial lift which utilizes an external source of high
pressure gas for supplementing formation gas in order to reduce the bottom-hole
pressure and lift the well fluids. The mechanism of gas-lift is fairly simple.
Gas is injected into the tubing string to lighten the liquid column and
decrease the bottom-hole pressure, which allows the reservoir to push more
fluids into the wellbore. At the same time, increased flow rates in the tubing
string and surface flow lines result in higher backpressure on the well and
adjacent wells that share a common flow line. This in turn causes a reduction
in well production rates. Therefore, liftgas has to be carefully allocated to
achieve maximum efficiency. The primary consideration in the selection of a gaslift
system for lifting a well or group of wells is the availability of gas and cost
of compression.
Of all artificial lift methods, gaslift most closely
resembles natural flow and has long been recognized as one of the most versatile
artificial lift methods. Because of its versatility, gaslift is a good candidate
for removing liquids from gas wells under certain conditions. Again, Production
of solids will reduce the life of any installed device that is placed within
the produced fluid flow stream, such as a rod pump or ESP. Gaslift systems
generally are not susceptible to erosion due to sand production and can handle
a higher solids production than conventional pumping systems. In addition to
the above mentioned advantages, gaslift systems can also be employed in
deviated wells without mechanical problems.
Gas
compressors are usually installed for gas injection or as booster compressors.
There are various methods of injecting gas into a well during gas lifting
operations. But the most commonly practiced method is the continuous flow gaslift
system. Here, the utilization of gas energy is accomplished by the continuous
injection of a controlled system of gas into a rising stream of well fluids in
such a manner that useful work is performed in lifting the well fluids.
It
is important to note that a number of factors affect the performance of a well.
An understanding of these factors will allow the designer of a given production
system to appreciate the need to obtain all available data before his design
work begins. Some of the most common factors that will be considered in view to
production optimization are discussed below:
1.1.2 Productivity Index (PI) and well Inflow
Performance Relationship
Accurate
prediction of the production rate of fluids from the reservoir into the
wellbore is essential for efficient artificial lift installation design. In
order to maximize production of oil from a gas liftedsystem, it is often
necessary to determine the well’s production. The accuracy of this determination
can affect the efficiency of the design.
One
simple method of predicting a well’s inflow performance is the calculation of a
productivity index (PI). The PI is the ratio of fluid production in barrels per
day to the difference between the static reservoir pressure and the flowing
bottom hole pressure in pounds per square-inch. This can be written
mathematically as:
PI
= J = 
The Productivity Index represents a
linear relationship as can be seen from Figure
1.1:
Figure 1.1:
A typical Productivity Index curve
PI has been a useful tool for predicting the inflow
performance of a well’s production rate at a specific flowing bottom-hole
pressure. Studies over some given well’s producing life has brought the
accuracy of the PI into question. It has been found that whenever there is a
two phase gas-liquid inflow, the linear relationship between these variables
will cease to exist. This makes it conclusive that the PI is valid for one
phase production rate.
One of the basic assumption of Productivity Index is
the availability of a stabilized bottom hole flowing pressure. It is this word
‘stabilized’ that makes the PI a topic of concern in the oil and gas industry. This
is because, there is no reservoir in the real world that can be found to have a
stabilized bottom hole pressure as production unfolds.
The PI is also a function of existing reservoir
drive mechanisms. The term ‘drive mechanism’ as used in this context is used to
differentiate between reservoirs whose motive power is primarily a displacement
type as opposed to a depletion type.
Displacement type refers to strong active aquifer or
gas cap drive and depletion type refers to a closed reservoir or one in which
the motive power in the reservoir is primarily from gas dissolved in the oil.
It should be noted that reservoirs with the displacement type drive will
generally produce more reliable PI’s from well test rather than will the
depletion type. In the displacement type, there is little or no free gas (aside
from those existing in a gas cap) and; hence the reservoir capability to the
single phase liquid is greater than it would be if the free gas were present.
It should be pointed out that under certain conditions, there can be serious
limitations to PI determination from this type of reservoir (displacement
type). If a well is pulled too hard, then a localized depletion drive will
result and obviously the PI as determined will not be reliable for predicting
the well’s performance.
The depletion type reservoirs will yield fair reliable
PI’s only when the pressure draw- down is small compared to the shut-in
reservoir pressure.
Another approach to the correct prediction of a
well’s performance is to plot flowing bottom-hole pressure against production
rate. This plot is commonly called the ‘inflow performance curve’ and it was
first used by Gilbert in describing well performance. Typical curves are
illustrated in figure 1.2 below and
they differ depending upon the type of reservoir. The curve for strong water
drive is essentially a straight line as discussed above under Productivity
Index. The determination of the non-linear relationship observed for solution
gas drive wells present a significant problem. A publication by Vogel in
January, 1968 offered a solution in determining Inflow Performance Curve for a
solution gas drive reservoir when undergoing production below burble point. He
was able to show that flowing bottom-hole pressure versus rate plot is a
function of cumulative recovery changed. This then results in a progressive
deterioration of the IPR’s as depletion proceeds in a solution gas drive
reservoir system.
Figure 1.2:
Typical Inflow Performance Curve
1.1.3 Outflow
Performance Relationship/ Vertical Lift Performance
The outflow pressure drop required to lift the fluid
from the perforations to the wellhead is another factor that must well be
understood in order to accurately predict well performance. This outward flow
of fluid from the wellbore to the surface is what is generally called the
Vertical Lift Performance (VLP). The VLP is completely independent of IPR, but
are closely related because flow from the reservoir and subsequent outward flow
through the tubing must be equal at the wellbore.
Vertical Lift Performance predictions for various
tubular string size is a very critical area in production optimization as up to
75% of all flowing pressure loss occurs along the tubing. The prediction of the
outflow performance relationship is complicated by the multi-phase flow nature
of the fluids. Analysis of the outflow performance therefore requires the
accurate prediction of phase behavior of fluids at the various flow regimes
along tubular string, flowing temperatures, effective fluid density and
frictional pressure losses.
The results of the outflow performance are usually
presented graphically. The most common plot depicts how the flowing bottom hole
pressure (Pwf), varies with the flowrate for a fixed back pressure
(usually the wellhead or separator pressure). The resulting curves are termed
Tubing Performance Curves (TPC). Any
point on the curve gives the pressure required at bottom-hole condition, Pwf
to achieve the given surface flowrate against a specified back pressure.
1.1.4 Control variables
Control variables can be seen as those production
operation settings to be optimized. In this work, the control variables are:
the production rates and the lift gas rates.
1.2 Statement of Problem
Optimum
oil and gas production, a function of existing reservoir pressure, is the goal
of every major player in the ever increasing oil and gas sector. Often times,
during the primary stage of production, existing natural reservoir pressure may
not be sufficient to cause fluid flow from the reservoir into the wellbore
region through the production tubing to surface facilities; this might probably
be due to the viscous nature of the oil (i.e. high viscosity). This inadequacy
of the reservoir energy to lift the produced reservoir fluid from the wellbore
to the surface may be caused by one, or a combination of the following factors:
unwanted excessive pressure drop along the column of the tubing, the effect of downward
drag on the moving fluid due to its viscous nature, wells mismanagement,
improper perforation, over-sizing or under-sizingof production tubing etc. For
these reasons, an artificial lift system installation is often considered
during the development of a well or field. Even after the installation of this
production aiding system, the issue of excessive pressure drop and deviation in
rate values of actual production from anticipated production is not totally
solved. This is due to the fact that production related problems such as: rate
allocation problem of lift gas, corrosion handling ability, temperature
limitation, well depth, production rates, flexibility of the installation,
space, high GOR etc. still exist as a result of flow movement from the bottom
of the well bore to the surface.
Hence, the need to carry a
sensitivity analysis on some of these factors affecting production in order to
properly optimize oil production from wells that require gas lifting.
1.3 Aim and Objectives of Study
The ultimate aim of this study is
to formulate measures/means to properly maximize production (profitability)
from a gas-lifted field in a safe and cost-effective manner as compared to natural
flowing wells of a given field.
The objectives include:
1. To
use Production and System and Performance software (PROSPER) to optimize
production from each of the gas-lifted wells in the field.
2. To
develop a gas lift performance curve for each well.
3. And
by extension, to also derive a lift gas performance curve for the entire field.
1.4 Methodology
The methodologies that will be
employed in achieving the already stated objectives are presented as follows:
Literature review on the subject matter.
Collection of well and production data
from a gas-lifted field in the Niger Delta.
Using Production and Systems Performance
analysis software (PROSPER) to build a single well model from the available
data.
Using PROSPER to optimize production
from the entire field.
1.5 Relevance of Work
The aspect of research work on
production optimization from developed structures cannot be over emphasized. It
is no doubt that every operator in the oil and gas sector wants to make maximum
profit from optimum production of oil via a cost-effective investment
operation. Therefore, for a gas lifted well to be able to produce optimally, a
thorough sensitive analysis on some of the existing problems affecting
production optimization for a gas lifted system must be carried out. Hence,
this research work is relevant in the following areas:
1. To
maximize well production rate.
2. To
increase the producing life of an oil well through proper gas lift management
operations.
3. To
solve some of the lingering production problems affecting the smooth operations
of a gas lift installation.
4. To
enhance production of highly viscous crude accumulated at the well bore
vicinity.
1.6 Scope and Limitation of Work
This research work is basically carried
out to optimize oil production from gaslifted wells via the installation of gaslift
system. Data from XT field, a field in the Niger Delta will be used as a case
study. PROSPER software will be used to design the well models. To fully
optimize the XT field production system, sensitivity analysis will be performed
to ascertain the effect of changing the tubing, water cut, surface choke,
sub-surface safety valve sizing, skin and Gas-Oil Ratio (GOR) on the general
well production system.
Gaslift design
is a wide field, and a detailed description of the design process of a gas lift
system is beyond the scope of this work.