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Collaborating Authors
Unconventional and Complex Reservoirs
Abstract The demand for hydrocarbons is expected to grow worldwide. As a result, deeper reservoirs are being explored. Emulsified acid systems are preferred for the stimulation of high-temperature carbonate reservoirs with bottomhole temperatures (BHTs) of 275°F and above. The retarded nature of an emulsified acid system decreases both the acid reaction rate and the rate of corrosion. However, the lack of emulsion stability of these systems is a major problem associated with high-temperature applications (at 300°F and above). Corrosion inhibitors and intensifiers can interfere with the stability of an emulsified acid system, which consequently leads to higher corrosion losses. At the same time, there is a need for better inhibition systems to counteract the effects of corrosion at higher temperatures. In this paper, a combination of three intensifiers was used, based on the differences in their mechanisms for inhibitor intensification action. The study includes the effect of varying the concentration of each component, hydrochloric (HCl) acid strength (20 to 28%), and temperature (275 to 325°F) on the stability and corrosion rate using P-110/N-80 coupons. The unique combination of the corrosion inhibitor and three intensifiers with proper optimization created a system capable of passing a corrosion test at 300°F using 28% HCl acid. The temperature limit of the system can be extended up to 325°F using an additional intensifier with 25% acid strength. The present system can be used for acid stimulation of carbonate reservoirs with BHTs up to 325°F. This study revealed a better understanding of the effect of the intensifiers in an emulsified acid system and the synergism amongst them. This enabled the use of an emulsified acid stimulation on carbonate reservoirs having BHTs up to 325°F while reducing the corrosion rate to a level that meets the current market demand for acidizing operations. This work shows that emulsified acid systems can be used with HCl acid strengths ranging from 20 to 28% at high temperatures. The resultant better wormholing at high temperatures should also lead to enhanced oil production.
- Asia > Middle East (0.94)
- North America > United States > Texas (0.28)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
- Well Completion > Well Integrity > Subsurface corrosion (tubing, casing, completion equipment, conductor) (1.00)
- Well Completion > Acidizing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- (2 more...)
Heavy Oil and Tar Mat Characterization Within a Single Oil Column Utilizing Novel Asphaltene Science
Seifert, Douglas J. (Saudi Aramco) | Qureshi, Ahmed (Schlumberger) | Zeybek, Murat (Schlumberger) | Pomerantz, Andrew E. (Schlumberger) | Zuo, Julian Y. (Schlumberger) | Mullins, Oliver C. (Schlumberger)
ABSTRACT A Jurassic oil field in Saudi Arabia is characterized by black oil in the crest, with heavy oil underneath and all underlain by a tar mat at the oil-water contact (OWC). The viscosities in the black oil section of the column are similar throughout the field and are quite manageable from a production standpoint. In contrast, the mobile heavy oil section of the column contains a large, continuous increase in asphaltene content with increasing depth extending to the tar mat. Both the excessive viscosity of the heavy oil and the existence of the tar mat represent major, distinct challenges in oil production. A simple new formalism, the Flory-Huggins-Zuo (FHZ) Equation of State (EoS) incorporating the Yen-Mullins model of asphaltene nanoscience, is shown to account for the asphaltene content variation in the mobile heavy oil section. Detailed analysis of the tar mat shows significant nonmonotonic content of asphaltenes with depth, differing from that of the heavy oil. While the general concept of asphaltene gravitational accumulation to form the tar mat does apply, other complexities preclude simple monotonic behavior. Indeed, within small vertical distances (5 ft) the asphaltene content can decrease by 20% absolute with depth. These complexities likely involve a phase transition when the asphaltene concentration exceeds 35%. Traditional thermodynamic models of heavy oils and asphaltene gradients are known to fail dramatically. Many have ascribed this failure to some sort of chemical variation of asphaltenes with depth; the idea being that if the models fail it must be due to the asphaltenes. Our new simple formalism shows that thermodynamic modeling of heavy oil and asphaltene gradients can be successful. Our simple model demands that the asphaltenes are the same, top to bottom. The analysis of the sulfur chemistry of these asphaltenes by X-ray spectroscopy at the synchrotron at the Argonne National Laboratory shows that there is almost no variation of the sulfur through the hydrocarbon column. Sulfur is one of the most sensitive elements in asphaltenes to demark variation. Likewise, saturates, araomatics, resins and asphaltenes (SARA); measurements also support the application of this new asphaltene formalism. Consequently, the asphaltenes are very similar, and our new FHZ EoS with the Yen-Mullins formalism properly accounts for heavy oil and asphaltene gradients.
- North America > United States (0.94)
- Asia > Middle East > Saudi Arabia (0.48)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.98)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.98)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (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 > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
Combating Solids Precipitation and Depostition in ADHI Gas-Condensate Process Plant
Ahmed, Shujjat (Pakistan Petroleum Limited) | Qadeer, Suhail (Pakistan Petroleum Limited) | Bouamra, Reda (Pakistan Petroleum Limited) | Chaker, Ahmed Abu (Pakistan Petroleum Limited) | Jamaiuddin, Abul (Pakistan Petroleum Limited)
ABSTRACT Adhi gas—condensate field is located near Islamabad, Pakistan. Pakistan Petroleum Limited started fluid processing and recovery of Liquefied Petroleum Gas and Condensate around in 1990. The liquid stream was processed with no solids deposition in the past. Recently, the liquid processing circuit of the plant has experienced an increasing amount of black solid deposition, which is trapped into the liquid filters located in the plant. To identify the root causes of the problem of these solids depositional systematic approach was applied including taking various solid, liquid and gas samples from the plant inlet and various locations inside the processing plant and analyzing them for diagnostics. Based on the outcome of the root-cause analysis, a chemical mitigation strategy has been developed, tested and implemented, resulting in significant reduction in problems related with solid depositions in processing plant.
- Asia > Pakistan > Balochistan > Dera Bugti District > Lower Indus Basin > Guddu Block > Sui Field (0.99)
- Asia > Pakistan > Punjab > Upper Indus Basin > Potwar Basin > Adhi Field > Chorgali-Sakesar Formation (0.98)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (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)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 150635, ’Integrated Production Chemistry Management of the Schoonebeek Heavy Oil Redevelopment in the Netherlands: From Project to Startup and Steady State Production,’ by Andrew G. Shepherd, SPE, Stuart Mcgregor, and Ruud Trompert, Nederlandse Aardolie Maatschappij, and Sen Ubbels, Bob van de Gender, SPE, Theo van Ommen, SPE, and Sjoerd van der Knoop, SPE, Champion Technologies. The production chemistry management process undertaken during the design, commissioning, and startup of the Schoonebeek redevelopment faced challenging separation issues, saline water, and a multitude of other process conditions that resulted in a complex application portfolio. Chemical selection was conducted in adherence to health, safety, security, and environment (HSSE) directives and focused on unique produced fluid properties. Since startup, the success of chemical performance has come from the availability of chemical treatment programs and surveillance/sampling plans. So far, no contingency chemicals have been needed at the facilities. Introduction The Schoonebeek oil field was discovered in 1943 and operated until the late 1990s. A number of enhanced oil recovery methods were used in this field, including high- and low-pressure steam-floods, hot waterfloods, and in-situ combustion. The field is now being redeveloped, using low-pressure steam-flood with horizontal wells. Superheated steam, supplied by a combined heat and power (CHP) plant, will be injected into the reservoir through 25 wells adjacent to the production wells in 17 locations. Gross production will be evacuated from the reservoir through 44 horizontal wells in 18 locations using artificial lift pumps, with a casing vapor recovery (CVR) system included to improve the gross lifting capability. Production from each wellsite will be routed through a gross gathering system to the central treating facilities (CTF). The CTF will include the required facilities to separate the oil, water, and associated gas and treat the respective streams to export quality. Production Chemistry Management Compliance toward European chemical regulations (REACH) was one of main drivers for the short-listing of products to be applied in the Schoonebeek redevelopment. Schoonebeek crude oil has a relatively high API weight. Nevertheless, the crude oil is quite acidic, as seen in high total acid number and naphthenic acid values. Most (>90 wt%) of the naphthenic acids are in salt form, which means that they may affect oil/water separation. The crude oil also has very particular wax properties. A high cloud point and pour point indicate that wax precipitation and gelling in the facilities may become a problem during normal operations if not controlled. Furthermore, wax particles contribute to crude oil viscosity and also may affect separation. Fig. 1 presents an overview of the main chemical applications selected for treatment between the wellsites and the CTF and at the CTF itself, together with the main process vessels and streams.
Abstract A Jurrasic oilfield in Saudi Arabia is characterized by black oil in the crest and with mobile heavy oil underneath and all underlain by a tar mat at the oil-water contact. The viscosities in the black oil section of the column are fairly similar and are quite manageable from a production standpoint. In contrast, the mobile heavy oil section of the column contains a large continuous increase in asphaltene content with increasing depth extending to the tar mat. The tar shows very high asphaltene content but not monotonically increasing with depth. Because viscosity depends exponentially on asphaltene content in these oils, the observed viscosity varies from several to ~ 1000 centipoise in the mobile heavy oil and increases to far greater viscosities in the tar mat. Both the excessive viscosity of the heavy oil and the existence of the tar mat represent major, distinct challenges in oil production. Conventional PVT modeling of this oil column grossly fails to account for these observations. Indeed, the very large height in this oil column represents a stringent challenge for any corresponding fluid model. A simple new formalism to characterize the asphaltene nanoscience in crude oils, the Yen-Mullins model, has enabled the industry's first predictive equation of state (EoS) for asphaltene gradients, the Flory-Huggins-Zuo (FHZ) EoS. For low GOR oils such as those in this field, the FHZ EoS reduces to the simple gravity term. Robust application of the FHZ EoS employing the Yen-Mullins model accounts for the major property variations in the oil column and by extension the tar mat as well. Moreover, as these crude oils are largely equilibrated throughout the field, reservoir connectivity is indicated in this field. This novel asphaltene science is dramatically improving understanding of important constraints on oil production in oil reservoirs.
- North America > United States (1.00)
- Asia > Middle East > Saudi Arabia (0.48)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- (4 more...)
An Integrated Approach for Assessment of in-situ Scale Deposition Risk during Waterflooding in a Giant Carbonate Field, Offshore Abu Dhabi
Tariq, Syed (ZADCO) | Samad, Saleh Abdul (ZADCO) | Aouda, Abdel Hakim (ZADCO) | Afzal, Mohamed (ZADCO) | BenGherbia, Mourad (ZADCO) | Graham, Gordon (ScaledSolution)
Abstract A common flow assurance problem during waterflooding operations is the deposition of mineral scale due to mixing of incompatible brines. Deposition of mineral scale can occur anywhere in the production system (reservoir, near wellbore, wellbore, surface facilities) if certain conditions for deposition of scale are present (composition of mixed brine, dynamics of mixing, pressure, temperature and kinetics). Understanding where and how scale will deposit and its impact on production and operations is important especially for the mega offshore field development projects which use new generation of high value wells (long/multi laterals, MRC) associated downhole equipment (ICD, ICV, etc) and surface facilities. In this paper, we present a systematic approach to assessing the scale deposition risk with an example of the application to a giant carbonate field, offshore Abu Dhabi.
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (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 Linnorm gas condensate field, located in the Norwegian Sea is technically challenging. The high pressure and high temperature reservoir contains gas with CO2, H2S and traces of mercury. Although the gas is relatively lean, the associated condensate has waxy properties. The field is located in ~ 300 m of water, ~ 5,000 m below the sea bed and 200 km from land. Although there are production facilities within 30 to 70 km, this discovery was initially seen as "stranded gas" due to the absence of an export route with available capacity. The chosen field development is in the FEED phase and comprises of subsea wells tied back to a 20 year old oil production platform, with a ~ 55 km direct electrically-heated flowline. The gas is processed on the platform for export, via a new, joint venture pipeline to an onshore terminal. This paper will discuss the key development decisions, and issues, regarding this technically and economically challenging project, from the reservoir to the export of the processed gas. Specifically it will address the reservoir development strategy considering decisions taken to exploit the different reservoir formations with individual wells, in the context of maximizing gas recovery, within the sub-surface constraints. The wells and subsea concepts are particularly challenging, pushing the limits of existing technology and requiring some world first solutions for what will be the highest temperature subsea field development on the Norwegian continental shelf with the world's longest electrically heated flowline. The surface facilities design will add significant gas processing facilities (separation, mercury removal, water and hydrocarbon dewpointing and compression) onto the platform and extend its economic life. Along with the safety, space and weight issues to be managed, there are also numerous other platform integration decisions to be made in relation to the process, flare and electrical and instrument integration.
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Silver Pit Basin > Block 49/30c > Davy Fields > Brown Field > Rotliegend Formation (0.99)
- Europe > Norway > Norwegian Sea > Møre Basin > PL 442 > Block 6305/8 > Ormen Lange Field > Springar Formation (0.99)
- Europe > Norway > Norwegian Sea > Møre Basin > PL 442 > Block 6305/8 > Ormen Lange Field > Egga Formation (0.99)
- (30 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- (4 more...)
Successful Application of a Fit-for-Purpose Acid Program in the Tengiz Field
Ussenbayeva, K.. (Tengizchevroil) | Utebaeva, D.. (Tengizchevroil) | Molesworth, G.. (Tengizchevroil) | Dunger, D.. (Tengizchevroil) | Howery, R.. (Tengizchevroil) | Akwukwaegbu, C.. (Tengizchevroil) | Salikhov, T.. (Tengizchevroil) | Kamispaev, A.. (Tengizchevroil) | Zielinski, M.. (Chevron) | Yakovlev, T.. (Schlumberger) | Savin, A.. (Schlumberger) | Aglyamov, M.. (Schlumberger)
Abstract Tengiz is a unique, super-giant oil field located in western Kazakhstan that is characterized as a fractured carbonate reservoir with high concentrations of H2S. It is operated by TengizChevroil (TCO). Current production is ~ 530,000 BOPD from 70 active producing wells. As part of an effort to increase the field's production output, a workover and stimulation program was initiated in 2011 after a hiatus of more than five years from such activities. A sizeable part of this workover effort was a matrix acid stimulation program which took lessons learned from earlier acid stimulation campaigns in the Tengiz Field to develop a modified acid stimulation treatment design. The result of this most recent program was a significant and sustained response in well productivity. The key components of the 2011/2012 acidizing program include: 1) increased acid volumes ranging from 50-100 gal/ft and 2) an acid diversion system that included the use of a viscoelastic diversion acid and degradable fibers. Another factor that supported the success of the acid stimulation program was the involvement of a multi-disciplinary team that addressed both candidate selection and acid stimulation design. The TCO 2011/2012 Acid Program has shown incremental improvement in all 19 wells stimulated to date. The average initial incremental gain following stimulation is ~4, 240 BOPD per well and the overall improvement in the Productivity Index (PI) has more than tripled. Post-stimulation production logs have confirmed improvement in the production profiles, indicating the acid diversion methods are having a positive impact.
- Asia > Middle East (0.69)
- North America > United States (0.68)
- Asia > Kazakhstan > Mangystau Region (0.63)
- Asia > Kazakhstan > Mangystau Oblast > Precaspian Basin > Tengiz Field > Tengiz Formation (0.99)
- Asia > Kazakhstan > Mangystau Oblast > Precaspian Basin > Tengiz Field > Korolev Formation (0.99)
- Well Completion > Acidizing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- (2 more...)
Abstract In many oilfields the relatively small number of high-cost, highly productive wells, coupled with a carbonate and or sulfate scaling tendency (upon waterflood breakthrough of injected seawater) requires effective scale management along with removal of near-wellbore damage in order to achieve high hydrocarbon recovery. The nature of the well completion strategy in new fields such as frac packs for sand control and acid stimulation for carbonate reservoirs had resulted in some wells with higher than expected skin values due to drilling fluid losses, residual frac gel, fluid loss agents, and fines mobilization within the frac packs where applied. The paper will present how the challenges of managing impaired completions and inorganic scale forced innovation in terms of when to apply both stimulation and scale inhibitor packages to sandstone and carbonate reservoirs. This paper will outline a novel process for non-conventional batch chemical applications where bullhead stimulation treatments have been displaced deep into the formation (<20ft) using a scale inhibitor overflush. Not only does this benefit the stimulation by displacing the spent acid and reagents away from the immediate wellbore area, but the combined treatment provides cost savings with a single mobilization for the combined treatment. The paper will describe the laboratory testing that was performed to qualify the treatments for both sandstone and an HP/HT gas condensate carbonate reservoir. The lessons learned fromcarbonate corefloodevaluationunder HT/HP conditions when appling stimulation fluids with and without scale inhibitor present in the treatment stageswill be presented. Many similar fields are currently being developed in offshore Brazil, West Africa and Middle East, and this paper is a good example of best-practice sharing from another oil basin.
- Asia > Middle East (0.69)
- Africa (0.68)
- Europe > United Kingdom > North Sea > Central North Sea (0.28)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Moray Firth Basin > Witch Ground Graben > P.213 > Block 16/26a > Brae Field > Alba Field > Caran Sandstone Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Moray Firth Basin > Witch Ground Graben > P.213 > Block 16/26a > Brae Field > Alba Field > Alba Sandstone Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Fladen Ground Spur > Witch Ground Graben > P.213 > Block 16/26a > Brae Field > Alba Field > Caran Sandstone Formation (0.99)
- (4 more...)
- Well Completion > Sand Control > Frac and pack (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- (3 more...)
Abstract The US Gulf of Mexico is one of the few regions in the world where wells are completed in the deepwater Miocene and Lower Tertiary reservoirs. These deepwater plays have required constant technological improvement to equipment service capabilities in order to maintain integrity in the 30,000-psi environments and minimize risks. Although capable tools and guns have been developed, continuous assessment of reliability still remains vital in the exploratory processes. Testing for production analysis in deep and ultra-deep water is critical, and when target reservoirs produce heavy oil, gas and condensate, or are in HP/HT environments, planning safe tests with risk mitigation that can gather high-quality data is paramount. Because of the high rig rates for deep-water operations, prolonged periods of low temperature and heat loss that can affect production or enable hydrate formation and other environmental challenges cannot be ignored. Fluid volumes and water depths can increase well-control time and expense. Also, since well tests are conducted from mobile vessels, alarm and subsea equipment philosophies are critical to success, and well-test string configurations must be flexible yet control well safety. Obviously, all issues must be understood for the program plan to anticipate the potential challenges. The purpose of this paper is to explore these issues as well as discuss mitigation methodologies. The considerations, merits, and limitations of various solutions will be considered. Lessons learned from actual cases will compare the consequences of inadequate preparation to the benefits of proper design. This paper explains why and how the methods and equipment suggested should be used and will include: DP vessel testing Well integrity at extreme depths and pressures Functional pressure-operated tool windows Coiled tubing Cushion and mud-type criteria Hydrate prevention Perforating strategies.
- North America > United States (1.00)
- South America (0.93)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.47)