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Collaborating Authors
Improved and Enhanced Recovery
Systematically Study and Practice for Thermal Well Integrity in Liaohe Oilfield
Tong, Deshui (Liaohe Oilfield of PetroChina, Panjin, Liaoning province, China) | Liu, Mingtao (Liaohe Oilfield of PetroChina, Panjin, Liaoning province, China) | Xiong, Jimin (Liaohe Oilfield of PetroChina, Panjin, Liaoning province, China) | Chen, Ping (Liaohe Oilfield of PetroChina, Panjin, Liaoning province, China)
Abstract Liaohe Oilfield has developed heavy oil for more than 40 years, and accumulated a lot of experience in research and practice for well integrity under Cyclic Steam Stimulation, Steam Flooding, SAGD, In-situ Combustion. This paper will introduce the systematical achievements, including well completion design, casing selection, cementing slurry, string attachment, etc. Based on the continuous study of fundamental principles, thermal casing, details of pre-stress method and industrial evaluation, the well completion design method has been optimized and the practicality has been checked ultimately. In particularly, the pre-stress method has been deeply studied through experiments and calculations. We have made a further improvement on string attachments. According to thermal recovery environment and low-cost requirement, a Portland cementing slurry characterized with low Young’s modulus, high compressive strength, and good temperature resistance, has been researched and used in field. The pre-stress method for the completion string design is testified to be effective in some extent, because the stress pre-imposed can reduce the string stress and minimize the wellhead growth in thermal recovery. The newly researched cementing slurry has been systematically tested in laboratory, the results are excellent: Young’s modulus ≤6, compressive strength ≥21MPa, temperature resistance 350°C, cost lower than 1000$/t. Casing used in thermal well should have a good performance of collapse strength, and the thickness to diameter ratio is important as well as the premium connection. The newly designed anchor with 6-cylinder anchor claws attached the completion string can adapt with softy and hard stratum. With the standardization of all the measures used in Liaohe oilfield, the thermal well integrity becomes better and better. The statistical data shows that the casing damage rate lowered 34%, and the life of the thermal well prolonged at least 2 years on average. Some contents in this paper are novel, such as the result of the pre-stress experiment, Portland cementing slurry with low-cost and good performance, newly designed anchor, etc. We believe all the experience accumulated and introduced in this paper could give some useful directives for thermal well integrity all over the world.
- Geology > Geological Subdiscipline > Geomechanics (0.88)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.54)
- Well Completion (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
Solving Ultra-High Temperature Scale Challenges: A Case Study of Re-Use of Polymer Flooding Waters for Heat Exchangers
Yue, Zhiwei David (Halliburton) | Chen, Ping (Halliburton) | Draghici, Vlad (Halliburton) | Westerman, Megan (Halliburton) | Huijgen, Martijn (Halliburton) | Privitera, Angelo (Halliburton) | Hazlewood, John (Halliburton) | Hagen, Thomas (Halliburton)
Abstract An oilfield operator relies extensively on heat exchangers (Hexs) to break heavy oil emulsions. A workhorse inhibitor worked reliably to control thermally induced scale precipitation caused by local hard waters. However, an upsurge of scale-related Hexs tubing blockage occurred during a harsh winter that coincided with a breakthrough of enhanced oil recovery (EOR) polymer into some water sources. Through comprehensive lab testing, root causes of the failure were identified. A new product was developed featuring superior tolerance to variable production parameters, especially Hexs temperatures. Scale inhibitor efficacy is strongly influenced by overall scaling conditions including water chemistry, temperature, pressure, and presence of incompatible chemicals. In this study, scale precipitates collected from Hexs were characterized using environmental scanning electron microscopy techniques. New inhibitor chemistries were screened through thermal aging; then evaluated for inhibition performance by dynamic tube blocking methods at temperatures ranging from 42°C to 171°C. An additional performance test was designed for the final candidate to further investigate adverse impacts from the EOR polymer and incumbent scale product if a dual-product treatment is required throughout the field fluid system. The incumbent effectively inhibited scale formation at ≤120°C but showed reduced performance at 160°C. This result is consistent with field records indicating most tubing blockages occurred during the coldest days when Hexs temperature was raised to 160°C to increase heat to treat fluids. Meanwhile, it also suffered antagonistic effects from the EOR polymer. A dozen new inhibitor chemistries were studied including polymers and phosphonates. Polymeric inhibitors had higher thermal aging ratings but were less compatible with the waters involved. Ideal candidates must have thermal stability, high-temperature inhibition performance, and applicability to wide ranges of operational conditions, including Hexs temperature, water hardness, bicarbonate, and foreign substances. Thus, a single product can be applied to the entire field and simple dosage adjustments can readily handle most expected scaling risks. The new product passed all the criteria and significantly reduced operating and equipment replacement cost since deployment. This paper provides a unique scaling challenge that combined ultra-high temperature and EOR polymer influence, and a systematic approach to understanding and resolving the issue.
- North America > United States (0.48)
- Europe > United Kingdom > Scotland (0.28)
- Overview > Innovation (0.57)
- Research Report (0.48)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (0.51)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > Montana > Williston Basin > Bakken Shale Formation (0.99)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation (1.00)
Development of Novel Test Methodology to Understand the Mechanisms of Halite Inhibition and Environmentally Acceptable Halite Scale Inhibitors for High Temperature Application
Ho, Kimberley (Nalco Champion, an Ecolab Company) | Chen, Tao (Nalco Champion, an Ecolab Company) | Chen, Ping (Nalco Champion, an Ecolab Company) | Hagen, Thomas (Nalco Champion, an Ecolab Company) | Montgomerie, Harry (Nalco Champion, an Ecolab Company) | Benvie, Ronald (Nalco Champion, an Ecolab Company)
Abstract Halite deposition is most commonly observed in gas/gas condensate fields with low water cut, high TDS produced brines and high temperature. Halite is notoriously difficult to inhibit and there are limited studies focused on halite due to it being incredibly challenging to have an effective test methodology under laboratory conditions that reflect the field conditions. The mechanisms of halite inhibition are unclear. In the published literature, static jar testing is primarily used to evaluate the performance of halite inhibitors. It is not representative of dynamic field conditions and provides limited information of halite inhibition. A new methanol driven dynamic test methodology has been developed alongside a novel jar test procedure, which together provides an effective methodology to evaluate halite inhibition under both static and dynamic conditions and provides an insight into the understanding of the mechanisms of halite inhibition. Using these novel test methodologies, four short-listed inhibitor chemistries including environmentally acceptable inhibitors were assessed and categorised into two types based on the understanding of the mechanism. ➤ Nucleation/growth inhibitors. Inhibitors reduce the nucleation/growth of halite crystals and give good performance under both static and dynamic test conditions. ➤ Dispersion inhibitors. Inhibitor doesn't stop the nucleation/growth of halite crystals and gives poor performance under static conditions, but good performance under dynamic conditions due to dispersion effect. Both types of halite inhibitors have been successfully deployed in the fields through continuous injection or batch treatment. Coreflood tests were carried out to confirm the potential risk of formation damage during downhole batch treatment. Other deployment methods have been discussed such as through methanol injection line as both inhibitors are fully methanol compatible. This paper will give a comprehensive study of halite inhibition for challenged wells, including prediction, novel methodology, program of laboratory qualification, mechanism understanding and field deployment, coupled to the development of a chemical technology toolbox to design field halite applications. The value that a fuller understanding of halite control gives the industry is the ability to reduce/eliminate water wash application to control halite formation and so improve well operation time. If halite inhibition is considered at the capex phase of field development, provisions can be made for chemical injection facilities to maintain uninterrupted production.
- Europe > Norway (0.28)
- Europe > United Kingdom (0.28)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
Modeling a Series of Nonaqueous Field-Scale Inhibitor Squeeze Treatments in the Heidrun Field
Vazquez, Oscar (Heriot-Watt University) | Ommen, Theo van (Champion Technologies) | Chen, Ping (Champion Technologies) | Martin Olav, Selle (Statoil) | Juliussen, Bjørn (Champion Technologies) | Kolstø, Erlend Holand (Statoil) | Gustavsen, Øyvind (Statoil)
Summary When a conventional aqueous squeeze treatment is not suitable for preventing scale formation, a nonaqueous treatment may be applied. Generally, these types of treatments include a nonaqueous phase and can be divided into different types on the basis of the delivery system. Despite the name, most nonaqueous treatments still contain some water because of the scale-inhibitor (SI) hydrophilic nature; it only truly dissolves in water. The main purposes of this paper are (1) to model a series of polymer nonaqueous SI squeeze treatments deployed in the Heidrun field in the Norwegian sector of the North Sea, (2) to investigate alternatives to optimize the squeeze design by studying the effect of the overflush, and (3) to show the workflow to build the input-data model from the available field data. All the field-treatment designs under study included the injection of an amphiphilic-solvent phase as the SI carrier phase and injection of a diesel overflush. The simulation and optimization calculations were conducted using a specialized near-wellbore model for scale treatments. The simulation study matched the well water cut for the time of the treatment, followed deriving a pseudoadsorption isotherm that was used to describe the SI retention in the formation. Heidrun coreflooding data and SI-returns data were used to build the input model. Finally, a sensitivity study on the effect of the overflush on the squeeze lifetime was carried out on the basis of the created input models.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (0.63)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Blocks 16/7b > Miller Field (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > South Viking Graben > Block 16/8b > Miller Field (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6507/8 > Heidrun Field > Åre Formation (0.99)
- (8 more...)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- (2 more...)
Development of Non-Aqueous/Low Density Scale Inhibitor Package for Down-hole Squeeze Treatments
Chen, Ping (1 Champion Technologies) | Juliussen, Bjørn (1 Champion Technologies) | Vikane, Olav (1 Champion Technologies) | Montgomerie, Harry (1 Champion Technologies) | Benvie, Ronald (1 Champion Technologies) | Frøytlog, Cato (2 Statoil) | Haaland, Torstein (1 Champion Technologies)
Abstract Some of the wells in a North Sea field have a relatively low reservoir pressure. For those wells without gas lift installed, lifting heavy fluid out of the well when flowing back can be a problem. For this type of well, one of the options for the inhibitor squeeze treatments is to use a low density package to avoid pumping a large amount of relatively heavy brine based inhibitor. Through a research program, a polymer inhibitor and non aqueous solvent based package was developed for the squeeze treatments for the field. This paper will present the detailed discussions of the chemistry of the formulation package. A number of scale inhibitors were screened for the suitability with a low density solvent as a carrying fluid. Due to both environmental concern and different function groups attached on the inhibitors, very limited inhibitor candidates were found to be suitable for being formulated into the low density package. The paper will further present the laboratory evaluation results such as product compatibility, inhibitor partitioning from solvent to brine phase, inhibitor efficiency as well as core flood data. The paper will also present the field evaluation data. One well treated with this low density package squeezed a water based inhibitor with several times in the past. Due to the reservoir pressure depletion, the low density package was developed for the squeeze treatments. The same inhibitor used in the water based squeeze was formulated into the non-aqueous package. The field trial results show that none of the wells experienced lifting problems while back producing the inhibitor pill. In most of the wells, an improved oil production was seen and maintained for a while after the treatments. A possible mechanism for this will be discussed. In addition, a comparison was made between the treatments from the water based and non-aqueous squeezes.
- North America > United States > Texas (0.46)
- Europe > United Kingdom > North Sea (0.34)
- Europe > Norway > North Sea (0.34)
- (2 more...)
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.76)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (0.69)
- Europe > United Kingdom > North Sea > North Sea Basin (0.99)
- Europe > Norway > North Sea > North Sea Basin (0.99)
- Europe > Netherlands > North Sea > North Sea Basin (0.99)
- Europe > Denmark > North Sea > North Sea Basin (0.99)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Production and Well Operations > Well Intervention (1.00)
- (3 more...)
Abstract The Veslefrikk field, located in block 30/3 of the Norwegian sector of the North Sea, has been on production since 1989 and is in the decline phase. Due to seawater injection, commingled production and high reservoir temperature, severe tendency towards deposition of sulphate and carbonate scale has been observed. The economic consequences of scale and the benefit from scale control work had been assessed quantitatively and presented at the 2001 SPE Third International Symposium on Oilfield Scale (Tjomsland et al., 2001). The study showed that the scale control strategy had been an economic success. However, annually more than 4% of the well productivity was still lost due to scale deposition, and in consequence it was recommended to intensify the scale management procedures. A task force involving scale control experts from the licence partners was established. In co-operation with service companies, the group systematically assessed new scale control measures for use at Veslefrikk. In 2006 a benchmark against the 2001 study was performed to investigate if the scale control work had been improved. The results showed that the scale potential was approximately the same in the second period (June 1999–2005) as in the first (1993- May 1999), but a significant improvement in downhole scale control was now obtained through a more aggressive use of preventive scale inhibitor squeezes and the implementation of new technology. However, the study also concluded that scale inhibitor squeezes themselves in some cases caused formation damage, most likely due to the formation of water blocks. Recently a mutual solvent that can be incorporated as part of the squeeze pre-flush was qualified for use on Veslefrikk. This has not only reduced the risk of formation damage, but in some cases even increased productivity has been observed. Introduction The Veslefrikk field is located in block 30/3 of the Norwegian sector of the North Sea. The field has been on production since 1989. It was developed by a 24 slot wellhead platform with drilling facilities in combination with a semi-submersible process platform with a living quarter, Figure 1. The production rate peaked in 1995, and the field is now far into the tail production phase. Seawater injection has been the main method of pressure support, but gas injection has also been performed to increase the recovery factor. The first water breakthrough was observed during 1992. The field water cut has now reached 80–85%, and in average the produced water contains 50–60% seawater. The Veslefrikk reservoir is layered, consisting of several zones with independent pressure regimes and to some degree also different fluid systems. Commingled production is extensively used at the field, due to the limited number of well slots and to optimize the production rate. Scale potential at Veslefrikk The two most common types of scale in the Veslefrikk field are calcium carbonate (CaCO3) and barium sulphate (BaSO4). Calcium carbonate can precipitate if produced fluid containing formation water is pressure depleted, for instance when flowing into or inside the well. The calcium carbonate saturation ratio (SR) increases as the pressure is reduced (see Figure 2), mainly due to the reduced amount of carbon dioxide (CO2) dissolved in the water phase when the pressure is reduced (Tjomsland et al., 2001).
- Europe > United Kingdom (1.00)
- Europe > Norway > North Sea > Northern North Sea (0.65)
- Research Report > New Finding (0.54)
- Overview > Innovation (0.34)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > Block 30/6 > Veslefrikk Field > Statfjord Group Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > Block 30/6 > Veslefrikk Field > Dunlin Group Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > Block 30/6 > Veslefrikk Field > Brent Group Formation (0.99)
- (16 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Well Operations and Optimization > Produced sand / solids management and control (1.00)
- Production and Well Operations > Well Intervention (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
A Way Beyond Scale Inhibitors - Extending Scale Inhibitor Squeeze Life Through Bridging
Selle, Olav M. (Statoil A/S) | Wat, Rex M.S. (Statoil A/S) | Vikane, Olav (Statoil A/S) | Nasvik, Haavard (Statoil A/S) | Chen, Ping (Champion Servo) | Hagen, Thomas (Champion Servo) | Montgomerie, Harry (Champion Servo) | Bourne, Hugh (Champion Servo)
Abstract The Heidrun Field is located in the Haltenbanken area offshore Mid-Norway. The reservoir temperature is 85 - 88°C and the reservoir pressure is close to hydrostatic pressure, around 250 bar. Seawater injection is utilized to increase recovery and for pressure support. With Ba levels averaging about 200ppm, downhole sulphate scale deposition caused by seawater injection has been identified. The field came on stream in 1995. Heidrun presents a particular challenging scaling environment due to the combination of high Ba content, demand for environmental friendly chemicals, strong top-side emulsion tendency, limited hydrostatics and at times high draw down within the gravel packs. In addition, the high kaolinite content (20–30 %) in the reservoirs introduces the risk of fines mobilization leading to plugging within the gravel packs especially with the development of overflush fluids volumes used during squeeze treatments. Scale control started in November 1999 with regular squeeze treatments. However, initial squeezes suffered from short treatment life and evidence of fines related productivity decline. Under a joint R&D program, a multi-functional additive was developed that enhanced inhibitor adsorption, provided clay stabilisation and a certain level of scale inhibition. This paper presents both laboratory and field data to elucidate the mechanisms involved in extending squeeze life and clay fines stabilization with this additive. Introduction The Heidrun Field has been described in several papers over the past years and only a short overview is given here. The field is located in the Haltenbanken area offshore Mid-Norway, and was discovered by Conoco in 1985. It has been producing since 1995 with Statoil as operator. License owners are Petoro (64,16 %), ConocoPhillips (18.29 %), Statoil (12.43 %) and Fortum Petroleum (5.12 %). The hydrocarbons are present in three reservoirs of Jurassic age at depths around 2400 m TVD MSL. The reservoir temperatures are from 85 to 88°C and reservoir pressures are close to hydrostatic pressure, around 250 bar. Seawater injection is utilized to increase recovery and for pressure support. With Ba levels ranging from 60 to 300 ppm, downhole sulphate scale deposition caused by seawater injection was identified in well A-28 in May 2000. The reservoir sands are in general poorly consolidated and contain 20–30 % clay minerals, as shown in Table 1. Kaolinite is the dominant clay mineral and occurs commonly as pore fills and coatings, often packed as sub-rounded aggregates with poor crystal face development. Other type of clay minerals is mica and illite, which range from 5 to 10 %. Most of the producing wells have sand control devices installed (gravel pack or stand alone screen). Well productivity is high prior to water breakthrough. However, a rapid decline in productivity is noted after water breakthrough in perforated and gravel packed wells with prepacked sand screens that have been stimulated with mud acid/clay acid treatments. Water related productivity decline in open hole completed wells occurs at significantly higher water cuts. Downhole scale control presents a particular sever challenge due to a combination of high Ba concentration in the produced water, significant fines migration, demand for environmental friendly chemicals, strong top-side emulsion tendency, limited hydrostatics and at times high draw down within the gravel packs. Aqueous and non-aqueous squeeze treatments have been deployed on Heidrun since late 1999 to provide scale control. However, several wells have suffered productivity loss due to fines plugging in the gravel pack, which is believed to be caused by the overflush fluid volumes used during scale squeeze treatments.
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6507/8 > Heidrun Field > Åre Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6507/8 > Heidrun Field > Tilje Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > Block 6507/8 > Heidrun Field > Ile Formation (0.99)
- (6 more...)
- Well Completion > Sand Control (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
Abstract The Heidrun Field, located on the Haltenbanken area, is one of the major fields which came on stream in the Norwegian Sea since 1995. At peak production the field is capable of producing 38,000 m of oil and 6 MSCM gas per day. It also takes in 22,000 m of injection water each day. The field is characterised by the large clay content in its three formation sands Fangst, Tilje and re. Most of the producing wells are installed with gravel pack or screens due to poor sand consolidation. The reservoir has a bottom hole temperature of 85°C and a relatively low reservoir pressure of 250 bar, hence seawater injection for pressure support is needed. With Ba++ level ranging between 180 to 700ppm in the different formations, the potential for downhole sulphate scale deposition within both the formation and the gravel pack, after seawater breakthrough is extremely high. A scale control strategy based on preventive squeeze treatment is therefore desirable to minimise any formation damage caused by such deposition. However, two treatments using water based scale inhibitor carried out prior to 2000 had caused significant process problems during back flow. Severe emulsion problems were experienced, resulting in process upset and poor water quality. The low reservoir pressure meant that long clean up periods were needed with much deferred oil production. Such undesirable side effects make the operator less willing to take preventive action. Over the past 6 months, with the availability of an oil based scale inhibitor and a new ‘biodegradable, green’ water based product, we have successfully treated a number of oil producers with a wide range of water cut. In all cases, there was minimum process upsets on flow back and resumption of oil production shortly after. In the case with the ‘green’ product, it is most encouraging since this is the FIRST North Sea application and the chemical offers a high degree of biodegradability. This contributes significantly to the step improvement on the environmental impact when the return of a large peak of unwanted chemical is often associated with a traditional water based squeeze. In this paper we shall describe the processes of selection, evaluation, design, implementation and follow up of these new treatments. Based on these results, we have now established a treatment strategy which can be applied to wells producing from the different formations and with various water cut.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (0.84)
- North America > United States > California > Sacramento Basin > 2 Formation (0.99)
- Europe > Norway > Norwegian Sea > Åre Formation (0.99)
- Europe > Norway > Norwegian Sea > Halten Terrace > PL 062 > Fangst Formation (0.99)
- (14 more...)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)