B_prod

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B. PRODUCTION PROBLEMS B.1 SATURATION Saturation, as well as having a “radial” component in the form of invasion has a time component. As the reservoir is produced the water moves in to vacate the space left by the producing oil. This process continues until the oil saturation equals the residual value. Virgin Zone

Measuring water movements helps to detect and survey the rise of the water/oil contact, locate water fingers which could give unwanted water production.

Invaded Zone

oil oil water water

OIL

Matrix

Fig. B1: Saturation in a reservoir is broken down into the virgin and invaded zones during the drilling and open hole phase. During production the saturation changes reflect the movements of the reservoir fluids.

Many reservoirs are bounded on a portion or all of their peripheries by aquifers. The aquifers may also be so large compared with the reservoirs they adjoin as to appear infinite for all practical purposes, and range down to those so small as to be negligible in their effect on reservoir performance. When pressure decreases due to oil production, the aquifer reacts to offset or retard pressure decline providing a source of water influx or encroachement. Water may be injected to supply external energy to improve the recovery of hydrocarbons. The injected water may advance evenly or may channel through the streaks of better permeability leaving hydrocarbons behind the water front.

WATER

High Permeability Layer

OIL

Fig. B2: This, multiple zone reservoir, is now producting water from one layer. Water fingering in this higher permeability zone has created the problem.

A reservoir consisting of multiple layers and completed in several together can eventually give rise to a situation as pictured in Figure B2. The high permeability layer is producing water. (01/97) B-1

Introduction to Production Logging

B.1.1 Crossflow Thief zones can be defined as those zones that are considered open to the wellbore either by perforations or openhole completion which due to zone pressure differences remove fluids from the wellbore. The pressure differences are caused by zones depleting faster due to higher permeability. Hence, in the illustration above, the middle zone may become a thief zone as it produces.

P1

High Permeability Layer

P3>>P2

P2

In some cases this could be a hydrocarbon, in other cases water, but in all cases it generally makes the surface production rates unusable in predicting individual zone balance of material equations. It also reduces the potential production of the well and reservoir. In the case of injection wells the thief zones on an injection profile may appear as higher injectivity zones, depending on their relative permeability to the other injection zones. In most cases these thief zones will continue to take fluid from other zones, even when the surface injection rate is zero. This can largely distort any balance of material calculations if only the surface rates are applied to all the downhole zones. In either the producing or the injecting profile it is important to know the dowhole profile of the well for both the active and passive surface conditions. In a producing well a thief zone could be decreasing the overall surface production of hydrocarbons, or downhole it could be dump flooding a potential hydrocarbon zone with water. In most situations the most serious effects of a thief zone on overall well productivity will be in those areas where the wells are on quota and may, therefore, be shut in for a large percentage of the time. In injection wells specific zone pressure may not be as well supported as believed if only injection profiles are monitored and no attention is paid to the shut-in state. B.2 CEMENTING

P3

Fig. B3: Crossflow from a lower zone to a higher one. This phenomena happens in any direction.

In the case of a production well the thief zones are generally most noticeable when the well is in a shut-in surface condition. In this condition the higher pressure zones will tend to feed fluid into the lower pressure zones. (01/97) B-2

Cementing of the casing in place is one of the most vital operations in the drilling phase. It is necessary to have a perfect seal between zones to avoid unwanted fluid production or reservoir contamination. Cement slurry is pumped behind the casing to the required height. It is left to set for some time before any other operations. The cement quality has to be evaluated before the completion and any repairs made at that

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time. It is also essential to properly evaluate any measurement in cased hole. One of the major difficulties in cementing is the presence of gas zones. These will cause problems if precautions are not taken during the cement job. B.2.1 Channeling Channeling is generally defined as the ability of fluids to move in the region of the production casing annulus because of a lack of hydraulic isolation between the casing and the cement or the cement and the formation.

life by providing a breakthrough into the wrong zones. Channeling in producers can lead to the production of unwanted fluids; i.e., water from wet zones or gas from the gas cap or gas zone. In some cases this unwanted production can render a well totally nonproductive. Channeling may occur in three conditions. These conditions are: • Oil or gas well with water channeling up from a lower zone • Oil or gas well with water channeling down from a higher zone • Oil well with gas channeling down from a higher zone B.3 CORROSION Corrosion encountered in the Oil Industry involves several mechanisms, generally classified into three main categories:

Unwanted fluid flow

Bad Cement

• Electrochemical Corrosion • Chemical Corrosion • Mechanical Corrosion B.3.1 Electrochemical corrosion This type of corrosion is caused by phenomena that involve passage of current between one or several metals and an electrolyte, with transfer of ions and electron (Figure B5).

Fig. B4: A cement channel from the lower zone to the upper results in the production of unwanted fluids.

In injection wells channeling can permit the injected fluid to enter undesirable zones, thus reducing the overall effectiveness of either secondary or tertiary recovery systems. Pressure maintenance and flushing will not necessarily prolong the productive life of a well; instead, it may actually shorten the productive

Electrochemical corrosion accounts for the majority of observed downhole casing corrosion, and is mainly detected on the outer casing walls. Metal is attacked in four different ways: a) b) c) d)

Generalized Galvanic Corrosion Crevice Corrosion Pitting Corrosion Intergranular Corrosion.

(01/97) B-3

Introduction to Production Logging

Conductor _ e

Anode

Cathode

Tubing Leak

Metal ions (M+)

Electrolyte

Packer Leak

Fig. B5: General mechanism for electrochemical corrosion

B.3.2 Chemical corrosion This type of corrosion involves chemical reaction which may not produce appreciable voltages. Five different mechanisms are known to contribute to chemical corrosion: a) Direct chemical attack b) H2S attack (Sour corrosion)

Fig. B6: Leaks in the tubing and packer cause production problems.

The casing string(s) could leak allowing fluid to escape into another layer. This not only causes a loss in production but could contaminate water zones (Figure B7).

c) CO2 attack (Sweet Corrosion) d) Hydrogen attack e) Bacterial attack B.3.3 Mechanical Corrosion There are two basic mechanisms for mechanical corrosion: a) Stress Corrosion b) Erosion Corrosion

Casing Leak

B.3.4

Production Problems and Corrosion There are many potential problems caused by the numerous corrosion mechanisms. Any of the components of the completion string can leak – packers, tubings, etc., (see Figure B6). This will cause mixed production which could lead to further problems such as crossflow.

Fig. B7: Corroded casing allows fluids to escape back into a reservoir zone. (01/97) B-4

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B.4 APPENDIX: CONDITIONS PROMOTING CORROSION The conditions of the well tubulars, together with the presence of oxygen-rich, saline and corrosive fluids play a major role in the corrosion initiation and propagation. Figure B8 shows the conditions that promote the various corrosion mechanisms and Figure B9 locates them with respect to a schematic completion string.

Saline/ DOWNHOLE Poor Single Collars oxyg. Form. Solid Cement Joint TYPE Condt. Move. Metal Casing Casing Fluid B.H. OF Prop. Corrosive Anom. Stress CORROSION Fluids

Electrochemical

Chemical

Mech.

Galvanic Crevice Pitting Intergranular Chemical H2 S C O2 Bacteria Hydrogen Stress Erosion

Fig. B8: Conditions promoting corrosion

(01/97) B-5

Introduction to Production Logging

B.4.1 Conditions • Poor quality cementation: In a poor cement job, casing is exposed to saline formation water, acting as an electrolyte. Some shallow formation waters contain dissolved oxygen which accelerates corrosion rates. Non-sulfate resistant cement (construction cement) breaks down rapidly and exposes the casing to corrosive aquifer water.

CO2 and about 400 times more corrosive than H2S.

• Metal properties: Most casings show variation in metallic properties, from joint to joint, across the same joint, and from joint to collar. This produces galvanic cells, and is seen on electromagnetic logs as a variation in joint conductivity and magnetic permeability.

• Bacterial growth: Anaerobic Sulfate Reducing Bacteria synthesize H2S and promote chemical and pitting corrosion.

• Casing anomalies: localized casing anomalies can promote galvanic and pitting corrosion. • Corrosion at collars: collars are normally stressed and distorted, and present gaps. They often are starting points for galvanic, pitting, and crevice corrosion. • Casing stress: Stressed sections of casing can accelerate corrosion because of their distorted lattice structure. Hydrogen cracking occurs when hydrogen ions diffuse into the stressed metal. • Saline formation fluids: they act as an electrolyte and promote electrochemical and chemical corrosion. Notice that overall corrosivity of saline solutions increases with salinity to about 5% NaCl, and then decreases because of reduced oxygen solubility. Above 15% NaCl, the saline solution is less corrosive than fresh water. • Oxygenated fluids: either meteoric formation waters or injection water not treated can cause electrochemical and chemical attack. Notice that, for carbon steel, oxygen dissolved in water is about 80 times more corrosive than

(01/97) B-6

• Borehole corrosive fluids: Spent acids, brines, or H2S and CO2 in the production stream can promote chemical corrosion. • Fluid and solid flow: Erosion corrosion is caused by high velocity fluids, turbulence, sand production.

B.4.2

Measures to prevent or remedy corrosion Several measures are available to prevent or remedy corrosion in completion strings. They are listed here for information and not discussed in any details as each one is the domain of specialists: • • • • • • • • • • •

Engineering design Selection of materials and alloys Coatings Good cementing Choice of completion fluids Inhibitors and biocides Cathodic protection Run tubing and casing patches Workover to replace tubulars Tie-back liners Changes in completion

Useful elements to design prevention and remedial programs can be obtained from corrosion evaluation and monitoring using wireline logging tools.

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STRESS ACID

OXYGENATED/ SALINE FLUIDS

POOR CEMENT

CORROSIVE ANNULUS FLUID BIMETALLISM H2S CO2 STAGNANT FLUIDS

+

CORROSIVE FORMATION FLUID

H2O

Fig. B9: Location of Corrosion in Wells

(01/97) B-7