The document discusses water shut-off methods for depleted oil and gas wells using polymer injection techniques. It provides details on the impacts of water production on wells, including more complex separation and rapid corrosion. Main causes of water production are discussed, along with well-known shut-off techniques like polymer and gel injection. The benefits of the company's proprietary water shut-off technology using polymer composites are summarized, including increased oil recovery rates up to 80-140% compared to standard extraction methods. Application experience is provided on wells up to 6,000m deep and 190°C, decreasing water cuts by 75-95%.
The problem of water and gas coning has plagued the petroleum industry for decades. Water or gas encroachment in oil zone and thus simultaneous production of oil & water or oil & gas is a major technical, environmental and economic problems associated with oil and gas production. This can limit the productive life of the oil and gas wells and can cause severe problems including corrosion of tubulars, fine migration, hydrostatic loading etc. The environmental impact of handling, treating and disposing of the produced water can seriously affect the economics of the production. Commonly, the reservoirs have an aquifer beneath the zone of hydrocarbon. While producing from oil zone, there develops a low pressure zone as a result of which the water zone starts coning upwards and gas zone cones down towards the production perforation in oil zone and thus reducing the oil production. Pressure enhanced capillary transition zone enlargement around the wellbore is responsible for the concurrent production. This also results in the loss of water drive and gas drive to a certain extent.
Numerous technologies have been developed to control unwanted water and gas coning. In order to design an effective strategy to control the coning of oil or gas, it is important to understand the mechanism of coning of oil and gas in reservoirs by developing a model of it. Non-Darcy flow effect (NDFE), vertical permeability, aquifer size, density of well perforation, and flow behind casing increase water coning/inflow to wells in homogeneous gas reservoirs with bottom water are important factors to consider. There are several methods to slow down coning of water and/or gas such as producing at a certain critical rate, polymer injection, Downhole Water Sink (DWS) technology etc.
Shubham Saxena
B.Tech. petroleum Engineering
IIT (ISM) Dhanbad
Reservoir engineers cannot capture full value from waterflood projects on their own. Cross-functional participation from earth sciences, production, drilling, completions, and facility engineering, and operational groups is required to get full value from waterfloods. Waterflood design and operational case histories of cross-functional collaboration are provided that have improved life cycle costs and increased recovery for onshore and offshore waterfloods. The role that water quality, surveillance, reservoir processing rates, and layered reservoir management has on waterflood oil recovery and life cycle costs will be clarified. Techniques to get better performance out of your waterflood will be shared.
The problem of water and gas coning has plagued the petroleum industry for decades. Water or gas encroachment in oil zone and thus simultaneous production of oil & water or oil & gas is a major technical, environmental and economic problems associated with oil and gas production. This can limit the productive life of the oil and gas wells and can cause severe problems including corrosion of tubulars, fine migration, hydrostatic loading etc. The environmental impact of handling, treating and disposing of the produced water can seriously affect the economics of the production. Commonly, the reservoirs have an aquifer beneath the zone of hydrocarbon. While producing from oil zone, there develops a low pressure zone as a result of which the water zone starts coning upwards and gas zone cones down towards the production perforation in oil zone and thus reducing the oil production. Pressure enhanced capillary transition zone enlargement around the wellbore is responsible for the concurrent production. This also results in the loss of water drive and gas drive to a certain extent.
Numerous technologies have been developed to control unwanted water and gas coning. In order to design an effective strategy to control the coning of oil or gas, it is important to understand the mechanism of coning of oil and gas in reservoirs by developing a model of it. Non-Darcy flow effect (NDFE), vertical permeability, aquifer size, density of well perforation, and flow behind casing increase water coning/inflow to wells in homogeneous gas reservoirs with bottom water are important factors to consider. There are several methods to slow down coning of water and/or gas such as producing at a certain critical rate, polymer injection, Downhole Water Sink (DWS) technology etc.
Shubham Saxena
B.Tech. petroleum Engineering
IIT (ISM) Dhanbad
Reservoir engineers cannot capture full value from waterflood projects on their own. Cross-functional participation from earth sciences, production, drilling, completions, and facility engineering, and operational groups is required to get full value from waterfloods. Waterflood design and operational case histories of cross-functional collaboration are provided that have improved life cycle costs and increased recovery for onshore and offshore waterfloods. The role that water quality, surveillance, reservoir processing rates, and layered reservoir management has on waterflood oil recovery and life cycle costs will be clarified. Techniques to get better performance out of your waterflood will be shared.
Industry studies show that mature fields currently account for over 70% of the world’s oil and gas production. Increasing production rates and ultimate recovery in these fields in order to maintain profitable operations, without increasing costs, is a common challenge.
This lecture addresses techniques to extract maximum value from historical production data using quick workflows based on common sense. Extensive in-depth reservoir studies are obviously very valuable, but not all situations require these, particularly in the case of brown fields where the cost of the study may outweigh the benefits of the resulting recommendations.
This lecture presents workflows based on Continuous Improvement/LEAN methodology which are flexible enough to apply to any mature asset for short and long term planning. A well published, low permeability brown oil field was selected to retroactively demonstrate the workflows, as it had an evident workover campaign in late 2010 with subsequent production increase. Using data as of mid-2010, approximately 40 wells were identified as under-performing due to formation damage or water production problems, based on three days of analyses. The actual performance of the field three years later was then revealed along with the actual interventions performed. The selection of wells is compared to the selection suggested by the workflow, and the results of the interventions are shown. The field's projected recovery factor was increased by 5%, representing a gain of 1.4 million barrels of oil.
Water Injection & Treatment for Tight Oil EOR
EOR choices for light Tight Oil
Potential damage to reservoir and well bore.
Water Specifications & Treatment
Case Studies:
1. Advanced Water Flooding
2. Frac injectors?
3. Low Salinity Water Flooding
Topics Include:
Filtration
Water Quality
Reservoir Pressure
This document was produced as part of my final year project of training to obtain a petroleum engineering diploma.
The aim of this project is to make a comparative study between continuous and intermittent gas lift systems based on real data from an oil well in Algeria, and to choose the system best suited to increase the production of the well.
This study was carried out by a manual design using the method of “fixed pressure drop” for the continuous gas lift system and “fallback gradient” method for intermittent gas lift system.
We were able to determine at the end of this study that the system best suited to the current conditions of our well would be the intermittent gas lift system and we also proposed that it should be combine with the "plunger lift " system in order to increase the efficiency of the intermittent gas lift system by eliminating problems linked to the phenomenon of" fallback " thus increase the production of our wells.
production optimization nowadays is a vital thing to capture for every gas field to get proper production rate. That's they need proper way to optimize there production. Here I have discussed about the process of production optimization using prosper softer from petroleum expert.
Industry studies show that mature fields currently account for over 70% of the world’s oil and gas production. Increasing production rates and ultimate recovery in these fields in order to maintain profitable operations, without increasing costs, is a common challenge.
This lecture addresses techniques to extract maximum value from historical production data using quick workflows based on common sense. Extensive in-depth reservoir studies are obviously very valuable, but not all situations require these, particularly in the case of brown fields where the cost of the study may outweigh the benefits of the resulting recommendations.
This lecture presents workflows based on Continuous Improvement/LEAN methodology which are flexible enough to apply to any mature asset for short and long term planning. A well published, low permeability brown oil field was selected to retroactively demonstrate the workflows, as it had an evident workover campaign in late 2010 with subsequent production increase. Using data as of mid-2010, approximately 40 wells were identified as under-performing due to formation damage or water production problems, based on three days of analyses. The actual performance of the field three years later was then revealed along with the actual interventions performed. The selection of wells is compared to the selection suggested by the workflow, and the results of the interventions are shown. The field's projected recovery factor was increased by 5%, representing a gain of 1.4 million barrels of oil.
Water Injection & Treatment for Tight Oil EOR
EOR choices for light Tight Oil
Potential damage to reservoir and well bore.
Water Specifications & Treatment
Case Studies:
1. Advanced Water Flooding
2. Frac injectors?
3. Low Salinity Water Flooding
Topics Include:
Filtration
Water Quality
Reservoir Pressure
This document was produced as part of my final year project of training to obtain a petroleum engineering diploma.
The aim of this project is to make a comparative study between continuous and intermittent gas lift systems based on real data from an oil well in Algeria, and to choose the system best suited to increase the production of the well.
This study was carried out by a manual design using the method of “fixed pressure drop” for the continuous gas lift system and “fallback gradient” method for intermittent gas lift system.
We were able to determine at the end of this study that the system best suited to the current conditions of our well would be the intermittent gas lift system and we also proposed that it should be combine with the "plunger lift " system in order to increase the efficiency of the intermittent gas lift system by eliminating problems linked to the phenomenon of" fallback " thus increase the production of our wells.
production optimization nowadays is a vital thing to capture for every gas field to get proper production rate. That's they need proper way to optimize there production. Here I have discussed about the process of production optimization using prosper softer from petroleum expert.
Valudor DAF, dissolved air flotation, and SHURE technology combine with proce...William Toomey
FLUID PROCESS OPTIMIZATION with Fine Solids Removal through SHURE Advanced Cavitation Management Technology
and Valudor Process Performance Chemicals Process Water Reuse
his paper presents the Microbial Prospection for Oil and Gas (MPOG) method, which uses microbiological techniques to explore for oil and gas. These techniques are based on the principle that light hydrocarbons from oil and gas fields escape to the earth’s surface, and this increased hydrocarbon supply above the fields creates conditions favorable for the development of highly specialized bacterial populations that feed on the hydrocarbons. This leads to significant increases in the microbial cell numbers and cell activity of these specialized microbes. By developing methods to establish the separate activities of methane-oxidizing bacteria (a gas indicator) and those bacteria that oxidize only ethane and higher hydrocarbons (oil indicators), it is possible to differentiate between oil fields with and without a free gas cap, and gas fields.In unexplored areas, MPOG represents a cost-effective method for preliminary exploration work. In mature areas, the method is helpful for ranking seismically defined geologic structures by indicating possible infill locations, as a contribution to reservoir characterization. No geologic or seismic data are required to carry out microbial prospection. In areas that have not yet been investigated geophysically, this technique can be applied as wildcat prospection. The sampling points are laid over the surface to be investigated, in the form of a map grid. The biochemical activity of the HCO represents the cumulative parameters. These are calculated by
• quantifying the consumption of added hydrocarbons (methane and/or propane and butane) using gas chromatography and pressure measurements • determining the biological CO2 formation rate
Microbial enhanced oil recovery (MEOR) represents the use of microorganisms
to extract the remaining oil from reservoirs. This technique has the potential
to be cost-efficient in the extraction of oil remained trapped in capillary pores of
the formation rock or in areas not swept by the classical or modern enhanced oil
recovery (EOR) methods, such as combustion, steams, miscible displacement, caustic
surfactant-polymers flooding, etc. Thus, MEOR was developed as an alternative
method for the secondary and tertiary extraction of oil from reservoirs,
General Water Treatment For Cooling Water
0 INTRODUCTION/PURPOSE
1 SCOPE
2 FIELD OF APPLICATION
3 DEFINITIONS
4 CHOICE OF COOLING SYSTEM
4.1 ‘Once through' Cooling Systems
4.2 Open Evaporative Recirculating Systems
4.3 Closed Recirculating Systems
4.4 Comparison of Cooling Systems
5 MAKE-UP WATER QUALITY
6 FOULING PROCESSES
6.1 Deposition
6.2 Scaling
6.3 Corrosion
6.4 Biological Growth
7 CONTROL OF THE COOLING SYSTEM
7.1 ‘Once through' Cooling Systems
7.2 Closed Recirculating Systems
7.3 Open Evaporative Cooling Systems
TABLES
1 RELATIVE IMPORTANCE OF FOULING PROCESSES AND INSTALLED COSTS
2 WATER QUALITY PARAMETERS
FIGURES
1 PREDICTION OF CALCIUM CARBONATE SCALING
2 CALCIUM SULFATE SOLUBILITY
3 CALCIUM PHOSPHATE SCALING INDEX
Presentation of TCTM and its truly revolutionary technlology: ETCT: Environment-friendly Thermochemical Treatment
The most modern, cost-effective, fully-automated and environment-friendly method of stimulation of crude oil, bitumen and shale oil extraction known in the world.
The lifecycle of developed fields, onshore and offshore will go through different stages of production up to the decline into late field life. Effective reservoir engineering management will lead to prolonging the life of field if a cost effective processing surface facilities strategy is put in place. Factors that lead to the decline in oil production or increase in OPEX may include increased water production, solids handling and the need for relatively higher compression requirements for gas lift. In order to maintain productivity and profitability, an effective holistic engineering approach to optimizing the process surface facilities must be utilized. The challenges of Optimizing Mature Field Production are: 1. Reservoir understanding with potential definition of additional reserves 2. Complete re-appraisal of the operability issues in the production facilities 3. Develop confidence to invest to optimize the process handling capabilities and capacity 4. Low CAPEX simplification of the surface facilities infrastructure to meet challenges 5. An implementation plan that recognizes the ‘Brownfield’ complexities 6. Selection of suitable optimum technology, configuration and training 7. Optimum upgrade plan of the facilities with minimum production losses Successful operation of mature fields and their surface facilities requires successful change management to the new operating strategy. Using a holistic approach can maximize the full potential of mature processing facilities at a manageable CAPEX and OPEX.
Dr. Wally Georgie Dr. Wally Georgie has a B.Sc degree in Chemistry, M.Sc in Polymer Technology, M.Sc in Safety Engineering and PhD in Applied Chemistry with training courses in oil and gas process engineering, production, reservoir and corrosion engineering. He has worked for over 37 years in different areas of oil and gas production facilities, including corrosion control, flow assurance, fluid separation, separator design, gas handling and produced water. He started his career in oil and gas services sector in 1978 based in the UK and working globally with different production issues then joined Statoil as senior staff engineer and later as technical advisor in the Norwegian sector of the North Sea. Working as part of operation team on oil and gas production facilities key focus areas included optimization, operation trouble-shooting, de-bottlenecking, oil water separation, slug handling, process verification, and myriad other fluid and gas handling issues. He then started working in March 1999 as a consultant globally both offshore and onshore, conventional and unconventional in the area of separation trouble shooting, operation assurance, produced water management, gas handling problems, flow assurance, system integrities and production chemistry, with emphasis in dealing with mature facilities worldwide.
2. 30.10.2009 2
No one is questioning the fact that we have either reached or will soon reach “peak oil”;
that existing fields are being depleted at the rapid rate of 7 percent a year, and that the
search is on for “unconventional oil” as alternative forms of energy are slow to reach
critical mass. .
We have already seen evidence that oil production tends to rise for a number of years,
then decline. Most geologists believe that on a worldwide basis, production will also
eventually begin to decline. Opinions vary as to when the decline used to begin. Typical
dates were between 2007 and 2014, although some believe the decline will not begin
until 2020 or later. .
One reason why geologists are predicting a decline in production is the fact that oil
discoveries (excluding Oil Sands, Oil Shale, and other “unconventional” sources) began
declining over 40 years ago.
5. THE IMPACT OF WATER PRODUCTION
ON OIL AND GAS WELLS
Water production is a major technical, environmental, and economical
problem in oil and gas production.
Water Production results in:
• More complex water–oil separation
• Fines migration
• Hydrostatic loading
• Rapid corrosion of tubular and well equipments
• Rapid decline in hydrocarbon recovery
• Premature abandonment of the well
Water production limits the productive life of oil and gas wells
Produced water represents the largest waste stream associated with oil
and gas production.
6. I. Water coning
II. Global increase of the water and oil contact
III. Water arrives
through a high
permeability
Layer
IV. Water flows through one or more
fractures that connect the aquifer to the well
7. MAIN CAUSES OF WATER PRODUCTION
M e c h a n i c a l p r o b l e m s :
• C o r ro s i o n o r w e a r h o l e s
• E xc e s s i v e p re s s u re
• F o r m a t i o n d e fo r m a t i o n
• F l u i d i n v a s i o n i n t o w e l l b o re
C o m p l e t i o n - r e l a t e d p r o b l e m s
F ra c t u r i n g o u t o f zo n e
Re s e r v o i r d e p l e t i o n
8. WELL KNOWN WATER SHUT - OFF TECHNIQUES
There exist countless techniques, including polymer and polymer/gel injection,
other gel systems, organic/metallic cross linkers, various combinations of any of
these, mechanical solutions, cement plug solutions and hundreds of other,
different, mechanical and chemical methods for water shut-off.
From amongst all these, our experience shows that, for many cases, innovative
water-control technology can lead to the most significant cost reductions and
improved oil production.
9. POLYMER FLOODING TREATMENT
Polymer flooding as one of the best Chemical Enhanced Oil Recovery mode
is a very effective method of stratum water shut-off that increases oil/gas
recovery and reduces water production. It significantly increases percentage
of oil/gas recovery by reducing the water production percentage at an equal
quantity of extraction.
Polymer types:
• Biopolymers
• Synthetic polymers
10. DIFFERENT POLYMERS COMPARED
Type Advantages Disadvantages
PAA: Polyacrylamide
(Partially hydrolyzed)
- high yield in normal
water
- high injectivity
- not salt resistance
- shear sensitivity
- O2 sensitivity
Hydroxyethylcellulose
(HEC)
- well soluble
- salt resistance
- pH sensitivity
- Fe+3 sensitivity
- low temperature
resistance
- no structural viscosity
Biopolysaccharide
(Xanthan, Scleroglucan)
- high yield in salt water
- shear stable
- temperature stable
- low adsorption value
- Injection problems
- bacteria sensitivity
- O2 sensitivity
- high cost
Co- and Terpolymers
- well soluble
- salt resistance
- temperature stable
- shear stable
- O2 sensitivity
- high cost
Source: Moawad T., ”A stimulation case study for economically improved oil recovery and water Shut-off strategies on the basis of
the stratified high temperature oil reservoir” Ph.D Tu-Clausthal, Germany.
11. Our Water Shut-off Technology is defined as an operation that hinders water from
reaching and entering the production well.
The complete procedure for the Technology is protected by utility patents that are
owned by the shareholders of our subsidiary corporation.
The Technology comprises the whole injection operation of the polymer composite
into the oil or gas well, based on the well´s geophysical properties.
Former experiences acknowledge that the treatment with our composite material
causes recovery of production capacity of the well as follows:
Additional 55% - 80% of oil/gas output of the well´s „first“ productive life – if we
treated only one well.
Additional 80% - 140% of oil/gas output of the well´s „first“ productive life – if
we treated selected well(s) of one oil/gas field.
T h e Water Sh u t-o f f T ec h n o lo gy
12. DYNAMICS OF WATER PRODUCTION
ON A WELL
0
10
20
30
40
50
60
70
80
90
100
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16
WaterProduction,%
Periods of time
Stage1: Water intrusion in the extracted product
Stage2: Constant increase of the water yield
Stage3: Sharp increase of the water inflow
Stage4: Stabilization of the water production
Stage5: Water shutoff technology application takes effect
13. Known methods of oil extraction give an efficiency
coefficient for oil/gas recovery only in the range 0.25 to
0.35
Application of our Technology increases the efficiency
coefficient from one well to within the range 0.60 - 0.80
The skill and experience gained over ten years´ successful
implementation of our Technology in the Russian and
Ukrainian oil/gas market guarantee the quality of our
services and the professional performance of our work for
our clients´ wells´ regeneration.
E F F E C T I V E N E S S
14. APPLICATION EXPERIENCE
- Well Depth range:
from 1,000 m to 6,000 m
- Well Bottom Temperature range:
from + 60°С to + 190°С
- Well Bottom Pressure range:
from 1,2 MPa to 25 MPa
15. TECHNOLOGY MATTER AND DUTY CYCLE
Water Stop Membrane
15 days
•Analysis of well characteristics data
and materials
20 days
•Preparing the well characteristics
dependet polymer composite
5 days
•Pumping the polymer composite into
the well
35 days
•Holding the well under pressure.
•Polymer composite in process of
transformation to complex molecular
Water Stop Membrane
16. Proprietary Water Shutoff Technology based on
patented synthetic polymeric composites.
Special technological cards allowing application of
our Technology to each specific case (based on the
basis of the technical passport and logbook of the
well).
A high-quality service, built from our long-term scientific
and practical experience, which adapts our research and
development groundwork to allow the swift and
efficient resolution of the many different complex tasks
specific to each well.
T H E E U C O G R O U P W I L L S U P P L Y
17. The process has been tested on more than 40 oil-producing wells in 11 different soils and
over a range of water salinity from 3,000 ppm to 200,000 ppm at a temperature of 70º
Celsius. The proportion of water to oil at the wellhead at commencement was between
70% and 100% and was decreased to between 5% and 20% over the majority of the
treated wells. In addition, the rate of oil production was increased in most of them. From
an economic point of view, the process of injection of the individually-tailored polymer
composite proved its claim of low operating costs and low acquisition costs for the
chemical constituents.
The tests for single phase flow that were conducted to determine the level of adsorption
of the polymer and its residual resistance factor (RRF) consisted of pumping.
The method has been applied in regions including Urengoy, Yamburg and Tyumen (major
drilling fields) in Russia; in the Ukraine for JSC "Chornomornaftogaz"; on offshore
platforms number 2, 4, 5 and 18, which are located on the continental shelf of the Black
Sea; and at the No. 4 sea stationary platform of the Gоlitsynsky gas condensate field.
Companies currently interested in developments using the technology include
SE “Urengoygazprom”; CC “Neftegazmontazh”; “Neftegazstroyservis”; RJCC “Gazprom”;
and SE “Yamburggazdobycha”.
18. The single most important element in the elimination of water influx through the
application of composite materials is expertise; expertise born of long-term experience in
the correct selection of composite materials based on geophysical studies of the well.
We carry out the water shut-off works through our local subsidiary companies. We draw
on 22 patented solutions, chemicals, know-how, and the Technology implementation.
These patents are owned by the shareholders of our subsidiary company.
After initial analysis, the chemicals modification and composite material injection into the
well, it is held under pressure about 35 days, following which the well re-starts production.
FOR THE SUCCESSFUL ELIMINATION OF WATER INFLOW, WE OFFER:
1. To design a synthetic polymeric composite specific to the well’s properties, including
the methodology for absorption zone isolation and in response to the formation of the
water flow in the borehole;
2. To follow our methodology for composite calculation from 36 base materials and 20
additives;
3. To employ our Technology to inject the specific composite into the well mouth;
19. Before our advice and suggestions about using of our technology in specific wells,
the customer should provide to us following information:
1. The well performance in m3 per day.
2. Reservoir pressure in MPa.
3. Well temperature in º C
4. Static pressure in MPa
5. Dimensions of the lower zone of the well.
6. Water volume measurement at the wellhead in m3.
7. Supplemental information about geophysical and hydrodynamic studies – if any.
8. Supplemental information about fluid saturation of the layers – if any.
9. Supplemental information about layer’s pressure, temperature: the initial and in the
dynamic – if any.
10. Supplemental information about the dynamics of the gas flow and mineral extraction
– if any.
11. The design depth of the well in m.
12. Real depth / actual depth of the well in m
13. Perforation intervals in the water reservoir 1,2,3,4 etc. / 1,2,3,4 , etc.
14. Cementing condition (state of cement stone) throughout the whole production casing
and production sectors too.
15. Real excavation performance (oil, gas and gas condensate) of the well from the
beginning of its development in m3
16. Debit of well productivity for all operation/production life.
17. Liquidity of recovery and saturation (gas, oil, condensate factor, etc.).
20. 18. All available well logging books, their recording data and hydrodynamic studies.
19. Samples (core) reflecting all available characteristics of the well.
20. Technical Operations´ chronology (in terms of the history of the well).
21. Well construction (geometric parameters) and compressed pressure.
22. Supplemental information about construction of the well and the pressing pressure –
if any.
23. Supplemental information about the arrangement of the tubing, the condition, the
size, etc. – if any.
24. Construction of the wellhead (types column head and CT).
25. Pipeline scheme and its condition.
26. Construction of the mouth (types of columns/casing and design of Christmas tree of
the wellhead.
27. Supplemental information about the history of the well.
28. Data of the well repairs/corrections or well work-over (if they were done) and results.
29. Attempts to activate/recover the well, efforts of reserves intensification or
application of waterproofing technology. What kinds of technologies were applied?
30. Wells´ geographic location and transport routes to it. GPS coordinate.
The full range of necessary works and equipment to be used for the application of the
specific polymeric composite can be prepared only after determining and expert analysis
of each specific well’s characteristics.