Sick Well Analysis

SICK WELL ANALYSIS ANALYSIS OF SICK WELLS - A SYSTEM APPROACH

Oil and gas production, in broad sense of word, can be subdivided into three or more separate fields of science and technology.

Production process in the reservoir:

Geosciences and Reservoir Engineering

Production of oil and gas from the well:

Reservoir and Production Engineering

Surface gathering and transportation:

Production Engineering

Therefore it is quite evident that in the context of well or reservoir analysis, knowledge of geosciences, production as well as reservoir engineering is equally important

TYPE OF WELLS

1) Oil wells: Exploratory / Development.

- Self flow.

- Having influx, but no flow to the surface.

2) Gas wells: Exploratory / Development.

- Low pressure

- High pressure

3) Injection wells: Gas / water

SYSTEM APPROACH

- WHAT IS A SICK WELL?

A well is termed as sick when it is proved or indicative of hydrocarbon bearing but having little productivity or producing with excessive quantity of unwanted fluids.

Similarly, an injection well (either drilled as an injector or converted) is considered to be sick when its intake is low.

Based on the performance, it is an accepted practice to keep such wells under sick category.

This approach provides first guidelines towards further action.

However, the above concept does not speak anything about the real potential of the well. Hence, a better yardstick would be to compare the present performance of a well with its best known producing /intake capacity.

- THEREFORE

In the truest sense, a well can be considered as sick when its performance is appreciably different from its best-known capacity.

Once, this definition is agreed to, it may delete or add a few more wells,as sick, based on the present performance only.

But a closure look into this definition will reveal that it has got its own limitation regarding data gap. To adopt such practice, it is essential to have a reference parameter.

The parameter, which is widely used to rate a well, is known as Productivity Index for producing well and Injectivity Index for an injector.

Throughout the producing history of a well, Productivity Index measurement can be used in determining, if the well is producing without any damage. In case of abnormal deviation remedial measure can be taken.

But in real field situation this parameter is often missing, especially for the wells, which have never flowed.

Sick well analysis is a continuous process, which updates the present scenario. Regular studies are carried out as a routine within a organization from time to time at different levels. An example may give some idea about the kind of study which can be taken up.

Salient features of one such study are discussed in brief.

ON SHORE VI PLAN VIIPLAN VIIIPLAN

Total number of

Wells at the

Beginning 6 325 464

No. of wells fallen

Sick during the period933 2485 3822

No of wells available

For liquidation 1379 2810 4286

No of wells liquidated

During the period 1054 2346 3224

Findings of another study carried out in one of the Operating Regions revealed that nearly 2500 tons per day of oil production is feasible if all the wells are worked over successfully.

Both studies together have come with interesting observations.

There is increasing trend of sick wells with time.

At a given time, percentage of sick wells can be as high as

20 to 30 % of total operating wells

Appreciable quantity of oil is blocked behind idle wells

Planning,

Execution

Monitoring

PLANNING

Step 1: Identify the wells on the basis of present performance

Step 2: Data collection

Nature of data Source

-Geological/Reservoir

Model/map Seismic ,Log, drilling

Formation Type Core, Log, Well cutting.

Pay thickness (Iso- pay Map) Log

Porosity (Iso-porosity map) Core, Logs.

Permeability (Iso-permeability map) Core, Well tests.

Pressure (Iso-bar map) Well tests, DST.

Temperature Well tests, Logs

Formation Volume factor PVT,Correlation

Viscosity/Sp.Gravity Lab.Sample analysis.

Compressibility Core,Correlation

- Well Details

Well completion: Drilling Records.

Well Construction: Well data sheet

Casing /Tubing

Packer

Lift system

Wellheads

Productivity Index (Iso P.I map) Well Tests, DST.

Skin (Damage / Improvement) Well Tests, DST.

Flow Efficiency: Well Tests, DST.

-Production

Rate of Production Well Tests, Separator.

Gas oil ratio Well tests,

Water cut Sample analysis

- Environmental

Logistic Local Administration

Society

Safety

- Financial

Financing Cost.

Operational cost Local Finance

Statutory obligations

Price of produced fluids

Step III: Carry out technical analysis.

Probable causes of sickness

Diagnostic tools.

Remedial measures

The most frequent problems in a producing field in respect

of well performance are

Poor production

High water or gas production

Probable reason(s) for poor production

Low reservoir energy.

Low reservoir permeability.

High viscosity of the fluid.

Damage to well bore.

Inadequate lift mechanism

Mechanical trouble.

Unknown problems

Wells with high water or gas production

The common reason for excess water or gas production is

Rise of oil- water contact or expansion of gas oil contact.

Coning of water or gas.

Preferential movement of water or gas through high permeable streaks or fractures.

Leakage behind or through casing.

Rise of oil water contact:

This phenomenon is observed for a water drive reservoir.

Water drive term is used in designating a mechanism which

involves movement of water into the reservoir as oil and

gas are produced. Water influx into a reservoir may be edge

water or bottom water, the latter indicating that a water zone of

underlies the oil sufficient thickness so that water movement is

essentially vertical The natural source of water drive is the

result of expansion of water and rock in the aquifer. However it

may result from artesian flow also.

As the water encroaches either for bottom or edge water drive,

there will be increasing volume of water produced and

eventually water will be produced in all the wells.

Expansion of gas-water contact

Where there is an initial gas cap, oil is saturated and there is no

liquid expansion Energy. In this situation the energy stored in

the dissolved gas is supplemented by the gas cap. In case of

gas cap drive, as production proceeds and reservoir pressure

declines , the expansion of gas cap displaces the oil down

wards. This results increase of gas oil ratio (GOR) in

successively lower wells.

Coning of water /gas

Water cone forms where oil is underlain by water and the well

completed in oil zone only. When well starts flowing, it creates

a lower pressure zone near the well bore due to draw-down.

The water underlain tries to flow upward. The movement of

water is controlled by the vertical permeability of the producing

strata.

Similarly, gas coning occurs when gas oil contact is within well

and the well is completed in the oil zone .Similar mechanism as

that of water coning work for movement of gas in downward

direction.

Height of the cone will increase with the magnitude of pressure

drawdown

Preferential movement of gas /water.

This is observed when the reservoir is heterogeneous in respect

of permeability and the oil is considerably more viscous than

water. Many producing zones are having different permeability

in horizontal and vertical direction. Zones of lower or higher

permeability are often found to exhibit continuity through out a

reservoir or portion there of. Where such stratification exists, the

displacing water (either injected or natural influx) sweeps faster

through more permeable zones so that much of oil in the lower

permeable zones must be produced over a longer period of time

at high water cut.

Water cut in the producing well, at any time, depends on the

capacity i.e. kh of the producing well formation and the

capacity (kh ) of the of the zone which has broken through

water production.

Given a series of beds with thickness h1, h2 ......hn and the permeability k1, k2 . ......kn the surface water cut can be expressed as

fw = Qw/ Qw + Qo =

( 1.127 W(h(kw (hw / uwL

---------------------------------------------------------- -------------------

( 1.127 W (p( k w (hw) / uw L + (1.127 W (p (k o ( h) / uo Bo L

However, it is not easy to calculate water cut theoretically

as most of the time, required data will not be available.

The diagnostic tool, which have been proved to be quite

successful in the field is Production Logging

Step IV: Conclude studies. Suggest further action plan. The conclusions can be listed as follow

Group of wells A: Problems identified.

- Natural

Live with the situation

Delete from the list

Group of wells B: Problems and remedial measures are identified

Resources are available.

Techno-economically viable.

High priority

Group of wells C: Problems and remedial measures

are identified.

Resources are not available within

organization. Need to purchase

or hire technology from out side.

Techno economically viable.

Low priority.

Group of well D: Problems and likely solutions

are identified.

Resources are not available within organization.

Remedial measures have got limited success as per available case history.

Recommended to refer Central committee for Expert advice.

Group of wells E: Problems identified.

Wells are beyond repair.

Recommended to be deleted from sick well list.

Group of wells F: Data insufficient.

Plan to acquire data

Step IV: Carry out Financial Analysis

Step VII: Priority

The results of analysis are the first lead for priority assignment. However apart from techno economical superiority a few more factors are important for execution schedule as follows.

Specific need of the organization

Oil well

Gas well

Injection well.

-Potential of the well

Average output with routine work over.

Substantial gain with major work over.

Environment

Logistic and Social

EXECUTION

A flow chart of work over operation is presented here. The chart shows the relevant connection between Planning and Execution.

The project coordinator has a very important role to play in the management. He is the key person between various groups. The working style of a coordinator is discussed here.

Review of a project is a continuous process .A PERT (Project Evaluation and Review technique) is convenient tool for day-to-day monitoring, as it breaks down all the direct and hidden activities within a time frame. Alternately a bar chart also can be used form the same purpose.

Frequent meeting should be held involving all concerned

people. Working site is a convenient place to hold such

meeting. Every one should be made aware about the common

goal.

It is not a secret that operators tend to incline towards softer

option and the planners are rigid about their decision. The

coordinator must find a solution for such conflicts without

sacrificing the objective.

It has been observed that any failure (either in planning or

execution) has tremendous negative impact in the minds of the

concerned people. The coordinator must keep the moral and the

spirit of the people high. Mid course correction plan should be

discussed and be implemented.

Sometimes, same nature of job creates monotony in a person

resulting loss of interest in the work. The coordinator should try

to rotate people. How ever it should be done judiciously

avoiding any possibility of a misfit.

-Post operational appraisal of any work over is an important

aspect especially in case of unsuccessful attempts. After a

project is concluded a detailed evaluation both from engineering

and economic point of view. Sometimes the apparent success

may not reflect the real achievement An unbiased appraisal only

will say if the work over was really profitable and if not why?

The appraisal can be based on some frequently asked questions

- Did the work over go as per planning? If not why?

.. Inadequate planning?

.. Unforeseen problems?

.. Uncontrollable environment?

. Attitude of the people?

- Is the objective fulfilled? How the result compares

with expectation? If not why?

.. High expectation? Data quality?

.. Lack of knowledge?

.. Resources constraint?

..Too many compromise?

- Was the work over really profitable? If not why?

.. Did the cost of material go up?

.. Did the price of the produced fluids reduced?

.. Is there change in tax structure?

.. Were there excess of breakdown?

- What can be done?

..Carry on with the present set up but with

more meticulous attitude?

.. Hire an expert for constant guidance?

.. Recommend for a technology provider?

In a total flow system (from reservoir to the well bore and from well bore up to the gathering point) different nodes are involved. These nodes can be broadly identified as

Reservoir

Well bore

Casing and completion (packer etc)

Tubing

Well head.

Gathering system

For the performance analysis of any well all these nodes are to be thoroughly examined before coming to any conclusion. Apart from the history of the well, to gather additional information, two tests are very handy to start with

Production logging

Well testing

However, before recommending to carry out either test objective must be very clear and it should be ensured that the well is made ready to carry out the test.

-WHAT IS PRODUCTION LOGGING?

Production logging consists of running Geophysical instruments

called logging tools, into a well to measure various parameters.

These logs are run in producing as well as injection wells.

They can be under dynamic (flowing) or static (shut in)

conditions.

Production logging is one of the most important aspects of oil

field management. It provides an insight into the type and rates

of fluid flow in reservoir and well. It helps in problems like

Water entry location and sources

Non-performing perforations

Flow behind casing or tubing

Cross flow identification

Leaks in the tubing, casing or packer

Lost circulation zone

There is a family of tools provided by Schlumberger which is intended primarily for measuring the performance of producing and injecting wells. The tools include

Thermometer

Gradiometer

Continuous flow meter

Manometer

Caliper

Thermometer: Measure the temperature of well bore fluid under either shut in or flowing conditions. Particularly useful in detecting flow in casing annulus.

Gradiometer: Measure the difference in pressure over 2 feet of well bore, which is related to the mean density of the well bore fluids In some cases it may be affected by the hole deviation or friction component.

Continuous flow meter: With a spinner velocimeter it measures the velocity of the fluid, which is related to the volumetric flow rate. Primarily the tool should be used essentially

for monophasic flow regimes.

Manometer: Measure the pressure of the well bore fluid. Helpful in determination of productivity index for gas as well as oil wells.

Caliper: Measure the diameter of the casing or the hole.

Temperature logs : The temperature response can be seen as a function of depth, flow rate, and time of injection in an injection well in the following fig.

Similar relationship controls the temperature in producing wells, but the flow rates are usually lower. Difference between injection and producing wells is that the temperature in the latter group is commonly higher than the geothermal profile. A typical plot is shown

Case Histories:

Anomalous fluid flow behind the casing: The shut in and flowing Temperature on a water injection well is shown in the figure ( ). A continuous flow meter log indicated that there was no downward flow of fluid in the casing below 600 ft. Yet both the shut in or flowing temperature logs indicated that the water is being injected into the formation opposite the perforations. The flowing Temperature Log follows the classic pattern described in the literature. Below 3000 ft the slope of the Temperature Log approaches the slope of the geothermal profile down to the top of the zone where the water is being injected. Then below the zone of water injection, the temperature quickly returns to the geothermal profile. It is to be noted that just above the zone of water injection the injected water is more than 200 C cooler than the geothermal gradient even though the water injected from the surface is quite hot. The shut in

Temperature logs also follow the classic pattern. After the well has been shut in for 20 hours, the temperature is approaching the geothermal profile.(except in the water injection zone)

Evidently, this is a very unusual case, the injected water is leaving the casing at 600 ft, traveling down to the annulus, and entering the desired zone.

The necessary remedial actions are to cement off the casing the casing leak at 600 ft, and if necessary re perforate the zone at 3200 ft. Here, a single Production Log would have given the misleading information.

Leakage through casing:

Routine pressure measurement in one of the gas wells in a gas field showed much lower pressure than earlier recorded, although the well was not on production. There was no surface leakage also. To ascertain the cause, a temperature survey was carried out. The temperature log shows a drop in temperature around 700m. This was interpreted as movement of gas through damaged casing and being lost in the upper zone. The casing was perforated at the top and bottom of the suspected damaged zone and cement squeeze job was carried out. Again a temperature survey was carried out which shows no anomaly proving the job to be successful.

Though the interpretation of the temperature survey proved to be correct, but similar indication could have been due to tubing leakage as well. But the pressure recorded indicated some movement of gas. A spinner survey might have helped to confirm the cause of anomalous pressure. Unfortunately this was not available and decision had to be taken based on the temperature and pressure reading