Lack of reliable sealing materials with temperature rating over 600 °F (316°C) for downhole sealing and zone isolation applications in high temperature wells such as steam injection wells is a big material technology gap and concern for oil and gas industry. Traditionally, elastomers are the material chosen for downhole sealing applications. But this type of organic materials is prone to decompose when temperature approach 600°F (316°C) and even lower in wellbore fluids. Metal to metal seal may have the temperature tolerance, but lacks enough elasticity to provide reliable seal in downhole conditions. This paper will introduce a newly developed elastic carbon composite (ECC) and its use as an ultrahigh temperature packer element under extreme temperature conditions such as a steam injection well.
Tests show that the elastic carbon composite material has excellent thermal stability over 1000°F (538°C) and strong corrosion resistant to most downhole fluids, including hydrocarbons, brines, acids, etc. More importantly, it has also displayed improved mechanical strength (up to 15 KSI [103MPa]) and elasticity (6%). In addition, reasonable wear resistance observed from this carbon composite material proves it suitable for heavy oil recovery with high sand production. This new sealing material was fabricated into thermal packer elements which delivered superior sealing performance at high different pressure above 600 °F (316°C) and thermal shock cycles between 600 °F (316°C) and room temperature.
In this presentation, we will discuss the material design of this novel elastic carbon composite, the superior material properties compared to elastomeric seal materials, and the reliable performance of the ECC packer elements. The elastic carbon composite fills the technical gap of sealing material with temperature rating over 600 °F (316°C) and provides reliable solution to heavy oil recovery in the oil and gas industry.
Hydrogen sulfide and mercaptans are highly toxic. They can cause corrosion and contaminate fuels. For safe and efficient operation of oilfield applications, it is important to remove these constituents. Processes to remove sour gases with mercaptans include treatment of the hydrocarbon fractions with caustics, clays and hydro-treating, as well as the UOP Merox™ process. Another method comprises scrubbing with mono or di-ethanolamine in a regenerative amine system. These methods are ineffective in removing mercaptans.
Scavengers react more quickly with hydrogen sulfide than with other sour gases. For this reason it is a challenge to develop scavengers that scavenge all components of sour gas including mercaptans effectively.
This paper describes a new formulation that simultaneously scavenges hydrogen sulfide and mercaptans extremely efficiently. A new lab experimental procedure is presented that mimics the scavenging of sour gas in a tower application. The procedure uses a new analytical technique that simultaneously detects hydrogen sulfide and mercaptans. Gas concentrations of hydrogen sulfide and methyl mercaptan are detected before and after scavenging. Systematic performance evaluations show that the new scavenger simultaneously scavenges hydrogen sulfide as well as mercaptans.
Guo, Erpeng (Research Institute of Petroleum Exploration and Development, CNPC) | Jiang, Youwei (Research Institute of Petroleum Exploration and Development, CNPC) | Gao, Yongrong (Research Institute of Petroleum Exploration and Development, CNPC) | Shen, Dehuang (Research Institute of Petroleum Exploration and Development, CNPC) | Zhigang, Chen (Changqing Oilfield, CNPC) | Yu, Pengbo (Jinma Company Liaohe oil field. CNPC.)
SAGD (Steam Assisted Gravity Drainage) is commercially adopted as a main development methods for heavy oil reservoirs and oil sands. Improving recovery rate and heat efficiency of SAGD process is the main pursuit of all researchers. This paper aims to utilize a new additive with carbamide to reduce the steam consumption and lower down the residual oil saturation, hence to improve the recovery efficiency of this method.
Study on improving recovery efficiency of SAGD with carbamide in super heavy oil reservoir was carried out. 1-D flooding experiment were carried out at 50°C and 150°C to compare the sweep efficiency between different additives including carbamide, CO2 and alkali. Then simulation were run to evaluate the influence of carbamide to SAGD process. Different additives were compared and influences of different products from carbamide were analyzed in detail.
Study reveals that SAGD process can be greatly influenced by carbamide. Carbamide can gradually decompose into ammonia and CO2 in steam chamber. Great solubility of ammonia in water can effectively increase PH value of reservoir liquid and decrease residual oil saturation. The core flooding test results show that the oil displacement efficiency can be improved by 17.7% when 25% mass percent of carbamide was added at 150°C. And at 50°C, NH4OH showed 9% improve of sweep efficiency comparing to water. Solution of CO2 into oil can improve oil water mobility ratio. And in the simulation case the oil saturation in the core part of steam was reduced to 0.12 by ammonia (this value is 0.2 for steam). Distribution of CO2 and ammonia shows that oil drainage maybe start with viscosity reduction with CO2 solution and ends with ammonia flooding in steam chamber. With the result of this paper, the recovery factor of SAGD process can be improved by 15.4% and SOR can be improved by 20% when carbamide was co-injected with steam.
Calcium sulfate is inherently a difficult mineral scale during oil and gas production process because the amount of scale formed is much greater than that of barium sulfate at similar scale saturation index level, and it is very difficult to clean up. This is especially challenging in conjunction with HTHP stimulation treatments where compatibility of the scale control chemical with fracturing fluids is critical, and when longer-term inhibition performance is desired. A new solid inhibitor was developed for this purpose and applied in multiple wells in the Krishna Godavari (KG) basin offshore India to combat mineral scale within the proppant pack and production tubing over the long term, under extreme downhole conditions (T= 400°F, P=13,500 psi). Normally, downhole chemical injection mandrels and surface treatments cannot adequately control scale deposition under these conditions.
The new solid inhibitor product was made by adsorbing scale inhibitor onto a high-strength, proppant-sized substrate with a large surface area. The high-strength substrate were prepared by sol-gel chemistry through hydrolysis of aluminum alkoxides and formation of particles that are calcined and then sintered at high temperatures to produce a substrate with the desired strength and surface area. The scale inhibitor used exhibited excellent inhibition performance and good compatibility with metal based cross-linked fracturing fluid systems at high temperature.
Tests performed with proppants/substrates show that using high loading of the substrates with the proppant does not damage the proppant pack even under very high stresses, For example, API crush tests of a mixture of 80% conventional untra-high strength proppant with 20% substrate by weight at 13,000 psi produced less than 4.7% fines and 88% of the produced fines were larger than 100 mesh and the fracture conductivity of the pack is maintained. The results of comprehensive laboratory testing show the new solid inhibitor can prevent anhydrite scale up to 400°F, and is completely compatible with zirconium- crosslinked fracturing fluid at 350°F and above. To date, six fracture treatments have been performed using a total 23,800 lbs of this new solid inhibitor. The wellhead water samples are being collected for scale inhibitor residuals analysis, as the wells start to produce water.
To ensure compatibility of the inhibitors with high-temperature fracturing fluids, especially metal based cross-linked fracturing fluids, without compromising the inhibition longevity at high pressure and temperature remains a stiff challenge, although adding scale inhibitors to a fracturing fluid has been a well-established practice to provide long-term inhibitor protection during hydrocarbon production. The new approach described here meets this objective, extending the long-term well performance under HTHP conditions.
The scope of work for this study is to implement lean management concepts while supervising contractor's hydrotesting activity in a NGL plant construction project and present the outcomes. The obtained results can be utilized as an indication that introduction of lean thinking into day-to-day project management can enhance time management resulting into up to 50 % reduction in initial projected time to complete a specific task. Then, continuous improvement will lead to significant tangible and intangible results.
Applicable lean principals were utilized as methods to achieve targets. The lean method included: Visual management of the 5 Ss, team (PMT, PID, Contractor, and Sub-Contractor) involvement, and
The original proposal by contractor was to put the whole (Flaring) area hydrotesting activity on hold until the arrival of control panels to be shipped from the States. This would have resulted into a minimum of 3 months’ delays. While the turning around of the status and introducing lean thinking and planning, the hydrotesting activities was not postponed and were resumed instantly after root cause analysis and 5 Whys concepts implementation and re-planning, accordingly. The result was; by the time the panels arrived, 75.6 % of the test packages were completed, tested, and approved. Quality control and maintenance of the tested lines were also conducted successfully complying with Company recommended Standards and approved by PID.
It was observed that the performance of the team was significantly improved. Off course, as time passes, we were achieving targets that was originally scheduled for freeze. But it can be mainly attributed to the fact that every member of the team (PMT, PID, Contractor, and Sub-Contractor) was involved. The gravity of listening to suggestions and creating a 2-way communication channel from PMT made all team members take ownership into the process and keen on its success.
It can be concluded that planning and scheduling activities utilizing critical path analysis and PERT is essential as an initial planning step. Then, continuous improvement of the plans and schedules utilizing lean thinking can secure a completed project within budget and on a shorter projected period compared to projected periods estimated by standard scheduling tools alone.
Shady, Mohammed (Schlumberger) | Okafor, Charles (Schlumberger) | Pazzi, Jorge (Schlumberger) | Thomas, Oluyinka (Schlumberger) | Sule, Ayuba (Schlumberger) | Ali, Ahmed Moge (Schlumberger) | Hamdane, Toufik (GSA) | Hachelaf, Houari (GSA) | Allal, Abdelhalim (GSA) | Collela, Luigi (GSA) | Latronico, Roberto (GSA) | Marfella, Ferdinando (GSA)
Berkine basin is one of the main oil producers in Algeria. The upper, middle, and lower TAG-I are the target oil-bearing sands. In this basin, the ROD field is under pressure maintained mainly through water injection together with, to a lesser extent, gas injectors. The southern part of the field, "ROD Tail" has four water injectors targeting the middle TAG-I. In recent evaluation conducted through pressure measurement and an interference test, reservoir pressure was found to have declined by 35 bar within 2 years. This has prompted questions about reservoir management, mainly about the effectiveness of injector well capacity in maintaining reservoir pressure. Extensive data were gathered through well intervention; cleanout, perforation, and a caliper log. Many failed acid jobs were also noted in the history of these wells. An engineered high-pressure jetting operation via coiled tubing was executed, but injectivity could not be restored.
A methodology and workflow were adopted to identify the source of formation damage and scale deposition in the near-well area and around perforations. Solid samples were collected from the well and sent to laboratory to characterize formation damage type. The injection water was also analyzed by performing a standard 12-ion concentration analysis. An aqueous model simulator was used to confirm that the water was supersaturated with CaSO4 and CaSO4.2H2O. Finally, clay acid treatment was found to be effective. The treatment fluid was designed to prevent proppant dissolution and to clean fracture matrix interface. This was the first time this type of operation was executed after many unsuccessful conventional acidizing operations.
Excellent results were obtained after the acid stimulation treatment. The injection rate was found to increase significantly from 120 m3/d to 360 m3/d. Water injection pressure was also found to decrease from 243 bar to 220 bar, and the injectivity index increased by three times. Near-wellbore formation damage was removed, and formation permeability recovered. The clay acid treatment was applied to other wells in the field and similar results were obtained.
Yuan , Q. (Xi'an University of Science and Technology) | Chai , J. (Key Laboratory of Western Mine Exploitation and Hazard Prevention, Ministry of Education) | Li, Y. (Xi'an University of Science and Technology) | Zhang, G. H. (Key Laboratory of Western Mine Exploitation and Hazard Prevention, Ministry of Education)
ABSTRACT: To date, the Fiber Bragg Grating sensor (FBG) is one of strain measurement elements which can be embedded inside the rock model, this providing us an effective method to detect model deformation. The attachment methods, form of FBG sensor and the coupling status between the sensor and rock model are the major obstacles in the application of FBG sensor for model test. This study tried to research the detecting behaviors of FBG sensors which were packaged in different forms and materials. Two overlying strata models were built and two different forms of FBG sensors were embedded. Two FBG sensors were embedded vertically in model 1 and 2, respectively. The dimension of two models were 500 mm (L) x 400 mm (H) x 73 mm (W). The embedded two FBG sensors were named as FBG01,02 in modell and FBG03,04 in model2. FBG01,03 used copper substrate packaging, FBG02,04 used acetate ethylene plastic cylindrical packaging. The geometric similarity ratio of modell and 2 were 1:400. The experiment results showed that the model strata settlement deformation and the wavelength shift of sensors caused by deformation have linear-relation, the correlation coefficient reached to 0.9. The average sensing ratio of acetate ethylene plastic sensor and substrate sensor were 52.22 pm/mm and 26.81 pm/mm. The average sensing ratio of acetate ethylene plastic sensor was bigger due to the physical and mechanical properties of acetate ethylene plastic were closer to the rock model. However, the substrate sensor showed a better data variance due to the surface area of substrate packaging was large than cylindrical packaging. This suggests that the FBG sensor could be better applied to the rock model test if it has a large surface area and the sensor material is closer to the rock model.
Typical rock berms used to protect submarine pipelines may be damaged under shear by a first year grounded ice rubble keel. Physical model tests in a centrifuge have indicated that such damage occurs under loads less than those typical of actual design conditions. These novel tests have reproduced both failures of the rock berm and identified failure criteria for the ice rubble. The tests are of a preliminary nature given the discrete, rather than continuum, nature of the interaction event. The model freshwater ice rubble behaved as a frictional granular material under the shear test conditions with a peak friction angle of 38 degrees. Measured ice rubble shear strengths exceeded 65 kPa.
First year freshwater ice rubble large scale tests were conducted as part of the Pipeline Ice Risk Assessment and Mitigation (PIRAM) and Development of Ice Ridge Keel Strength (DIRKS) Joint Industry Projects. New finite element analyses of the PIRAM test set up indicate the boundary constraints on the test results. The measured PIRAM ice rubble shear strengths exceeded 35 kPa.
The first two test series indicate that ice rubble shear strength may exceed currently accepted design limits.
The Development of Ice Ridge Keel Strengths is a four-year collaborative venture between the C–CORE Centre for Arctic Resource Development (CARD) and the National Research Council – Ocean, Coastal & River Engineering (NRC-OCRE). The main focus of the project is to investigate the failure mechanisms associated with gouging ice ridge keels and the conditions under which these keels will continue to gouge without failure. This is important for the design of subsea structures in shallow waters, where ice keels have been observed to scour the sea floor, posing a threat to pipelines and subsea infrastructure. A series of near full-scale keel-gouge tests were carried out to investigate the strength characteristics of a first-year ice keel and its subsequent failure as it was pushed into an artificial seabed. The ice keels were constructed using freshwater ice blocks with a nominal thickness of 10 cm, produced in a cold storage facility prior to the start of the test program. The ice keels were constructed with the aid of a keel former that produced idealized keel geometries of 1.7 m depth, 4 m length and 3.5 m width. Once constructed, the keels were lowered into the water and left overnight to consolidate with air temperatures held at -20°C. The keel samples were tested using a custom-built frame that was designed and used in the Pipeline Ice Risk Assessment and Mitigation (PIRAM) Joint Industry Project. The frame applied a vertical surcharge load to the top of the keel whilst a soil tray was displaced horizontally, causing the bottom of the ice keel to interact with an artificial seabed. A total of ten keel tests were conducted in this test program. The parameters varied were the initial temperature of the ice (-3° and -18°C), the initial surcharge pressure (5-60 kPa), the soil tray velocity (1-20 mm s-1) and the consolidation time (19-48 hrs). An overview of the test program and preliminary results are discussed.
The use of subsea technologies and innovative field architectures as development solutions is fast becoming a reality. Thermal management is a key issue and using electrical heating such as the Electrical Trace Heated Pipe-in-Pipe (ETH-PIP) can be considered as an alternative to fluid circulation or chemical injection for preservation purposes.
The ETH-PIP is a standard Pipe-in-Pipe enhanced with 4 heat trace cables, and 2 DTS optical fibers spiralled against the inner pipe and covered by a high performance thermal insulation. As part of TOTAL qualification for the ISLAY project, the world first field development using subsea ETH-PIP technology, significant efforts have been put on the development and validation of flow assurance models able to predict the interaction of the active heating system with hydrocarbon mixtures during production, shut-down and restart.
This paper reviews and describes the development of the necessary models required to perform the thermal design and the flow assurance calculations all the way to the elaboration of a control system for monitoring the subsea operations. The focus has initially been put on the elaboration of a CFD model able to fully capture the local thermal behavior of every component. Finally, a simplified model describing the ETH-PIP thermal behavior is introduced into a multiphase flow simulator (Olga or Leda) to perform the necessary flow assurance calculations predicting the production fluid behavior during the transient active heating operations.
This paper also assesses the validation of the models. During the TOTAL qualification process, a 12m test rig has been set up for the validation of the the U value, cooldown and warm-up predictions coming from the CFD and Multiphase flow models. A larger scale validation has been performed comparing the fiber optics measurements to the model predictions during the commissioning test after installation. As an ultimate validation step, a complete offshore test has been realized during the Islay September 2012 shut-in period, where a series of warm-up, temperature maintainance and cooldown took place and successfuly compared to the models.
The elaboration and the validation of the ETH-PIP flow assurance model using CFD and Multiphase flow simulations enable the design and the prediction of the production fluid behavior during any operating scenarios. The developed models also open the door to the elaboration of a live monitoring system of the flowline thermal behavior which fully enables the ETH-PIP system operability for offshore operations.