Reservoir conformance control (RCC) might be fundamental designing profitable production technology in oilfields. Appropriate application of RCC methods can significantly result in improved IOR/EOR through reduced water production and profile correction. In the past decades, numerous techniques were extensively applied with these goals; however, the operators did not appreciate the silicates until mid-1970s despite the fact that emblematic professionals proposed the silicate gels as efficient alternatives to organic gel technologies. Recently, the attitude towards the extensive use of silicates in oilfields has changed. The silicate-based water shutoff treatments and profile control methods have been already used more than hundred times in Hungary, Serbia, Norway, USA, Oman, and other countries. In the past several years, the fundamental and applied research focused on elimination of inherent negative properties of pure silicate gels, and development of efficient and flexible technologies using polymers and nanosilica in the treating solutions. As a result, the diverse silicate RCC methods arouse high interest in oilfield applications. Today, the
The presentation summarizes the results of both the fundamentals and a pilot tests accomplished in the Algyő field, and critically analyzes the lessons to learn. Base on the publications disseminated until now it can be concluded that these field jobs demonstrate outstanding responds both in water cut and increased oil rate. It was also proved that the nanoparticle-induced (nucleated) formation of silicate gels could potentially be used in all types of porous and fractured reservoirs. In addition, the in-situ formed gels have outstanding thermal stability up to 150°C, the chemicals are mass-produced and available at low price, the job needs simple surface facilities, and customary human force to operate the RCC method. Consequently, the
Farzaneh, S. Amir (Centre for Enhanced Oil Recovery and CO2 Solutions, Heriot-Watt University) | Carnegie, Andrew (Woodside Energy) | Sohrabi, Mehran (Centre for Enhanced Oil Recovery and CO2 Solutions, Heriot-Watt University) | Mills, John R. (Centre for Enhanced Oil Recovery and CO2 Solutions, Heriot-Watt University) | Facanha, Juliana M. F. (Centre for Enhanced Oil Recovery and CO2 Solutions, Heriot-Watt University) | Sellers, Ben (Woodside Energy)
An undeveloped deepwater field, LC, in deepwater off the coast of Australia is a candidate for secondary waterflooding. But, will it be better to perform SeaWater Injection (SWI) and Produced Water Reinjection (PWRI), as has been done for all other water flooded oil fields in the same region, or to perform Low Salinity Water Injection (LSWI)? This major decision depends upon answering the questions: (1) Is LSWI likely to cost-effectively increase the oil recovery in LC? and (2) Will LSWI cause unacceptable risks to operating LC - for example by provoking formation damage and/or creating flow assurance problems? Previous investigations (
The low salinity water injection (LSWI) study reported here had three major objectives: firstly to investigate the potential of this improved oil recovery (IOR) technique for the field LC using the reservoir rock and fluids, Secondly, to further validate our proposed mechanism (
The objectives of the above mentioned experiments were successfully achieved. Some of the results were Notable: (1) the behaviour of natural surfactants in the oil of LC are influenced by both the ionic concentration and balance of the injection water, (2) when compared with SWI, LSWI recovers significantly more oil in corefloods, even though the clay fraction of the cores is lower than that which is often reported for cores that have reacted favourably to LSWI; and (3) removal of just the Ca2+Mg2+ divalent ions from the injection water unexpectedly increased the endpoint relative permeability of water.
The results of this extensive set of experiments present a case study for a real reservoir system, which includes a comprehensive set of data obtained by various methods at different scales and shed new insight into mechanisms of oil recovery by low salinity water injection. In addition, the oil in LC is biodegraded with an anomalously low asphaltene content. The dominant lithology is high permeability sandstone, which is mixed-wet in the oil zone. Field LC has a significant oil/water transition zone in which the wettability changes from being mixed-wet at the top to being water-wet at the bottom. It was important to use a simulator that can handle the effects of such wettability changes on the behaviour of LSWI.
The results of this extensive set of experiments present a case study for a real reservoir system, which includes a comprehensive set of data obtained by various methods at different scales and shed new insight into mechanisms of oil recovery by low salinity water injection.
Innovative technologies offering safer and greener designs for handling and transporting hydrocarbon-contaminated drill cuttings are of great interest for offshore platforms. Traditional offshore mud skips require use of crane lifts that take up large areas of rig space and hinder continued drilling under inclement weather conditions. This paper describes a unique bulk transfer system that improves offshore cuttings handling safety and provides an environmentally acceptable solution to cuttings waste management and discharge requirements.
The bulk transfer system consists of a single remote control panel unit, intermediate cuttings storage tanks, dual-pod pneumatic transfer unit, boat tanks with a logic control system, air compressor and an onshore hydraulic tipping mechanism. The unique drill cuttings storage with pneumatic transfer technology provides a means of storing drill cuttings in non-pressurized bulk storage tanks on an offshore rig. Cuttings are transferred in dense phase over long distances and heights to the boat storage tanks arrangement, enabling continued drilling over the duration of the well section.
The rig storage tanks include a self-emptying mechanism that generates full drainage, enabling continuous collection of cuttings until they can be pneumatically transferred to the boat storage tanks at variable discharge rates of up to 60 tons per hour, depending on the drill cuttings properties. The reduced height and footprint of this system optimizes space, while its improved efficiency enables reduced downtime in operations. The pneumatic blowing pump can move cuttings over 400 feet at a rate of 20 to 35 Mt/hr continuously to the storage tanks that are mounted on the support boat, enabling continued drilling in poor weather. The boat tanks are low profile and secured by ISO locks for safer navigation and quick emptying system for faster turnaround times. When the boat tanks reach the waste management facility onshore, the drill cuttings are safely emptied by a specialized hydraulic tipping mechanism that is designed to tilt the tanks up to 85 degrees for optimized discharge. The bulk storage tanks total capacity of 320 tons (290 Mg) using (100 m2) of deck space.
This bulk transfer technology enhances operational safety by significantly reducing the use of crane lift and minimizing environmental impact while enabling continuous drilling. The bulk transfer system also offers higher storage capacity, takes smaller floor space on the rig and enables mitigation of accretion or bridging in cuttings.
Wei, Bing (Southwest Petroleum University) | Li, Qinzhi (Southwest Petroleum University) | Li, Hao (Southwest Petroleum University) | Lu, Laiming (Southwest Petroleum University) | Pu, Wanfen (Southwest Petroleum University)
The environmental issues of the traditional oilfield chemistries are challenging the Enhanced Oil Recovery (EOR) industry. Therefore, eco-friendly chemical EOR methods must be quickly developed. In this work, an abundant natural polymer on earth, nano-cellulose, was extracted from the plant-based materials and then introduced to EOR. On the basis of the original nano-cellulose, a series of surface-grafting were performed for the interest to make it more favorable for EOR application, thus generating the well-defined nano-cellulose based nano-fluids. The EOR related properties including morphology, thermal stability, rheology,
This paper describes how demineralized water was substituted using inhibited sea water for hydro testing large capacity storage tanks and the huge cost savings achieved in the process.
ADGAS built two new Paraffinic Naphtha Tanks in 2014-2016. The tanks are of double walled doubled deck floating roof construction. The holding capacity of the tanks was approx. 50000m3.The tanks were to be hydro tested before commissioning. The volume of the Hydrotest water used was 50000 m3 for inner tank and 10000 m3for the annular space between the walls hence totaling 60000 m3for one tank.
Demineralized water was the primary choice for Hydrotesting. Minimum cost of desalinated water for testing one tank would be USD 222000 (USD 3.7x60000). Utilizing a conventional multifunction inhibitor would cost approximately USD 1.2 Million for both tanks. ADGAS used a newly developed floating corrosion inhibitor that would only wet the surfaces to be protected. Cost of this innovative chemical is only USD 11000/tank.
The corrosion inhibitors used was a float coat mixed with oxygen scavenger. Float Coat inhibitor is a biodegradable, nitrite and amine free, and environmentally acceptable for use. This was spray/brush applied on the tank walls for surface protection. Sea water was deoxygenated using an oxygen scavenger and gradually filled in to the tank. The floating properties of the inhibitor ensured uniform reach of the inhibitor.
Total cost savings achieved:
Cost of demineralized water: 222000×2= USD 444000. (Both tanks)
Cost of chemicals: Float coat USD 11000/tank Oxygen scavenger USD 49800/tank Total: USD 60800/tank
Float coat USD 11000/tank
Oxygen scavenger USD 49800/tank
Total: USD 60800/tank
Total cost of chemicals for two tanks: 60800× 2= USD 121600.
As UAE government has announced 2015 as innovation year and in line with ADGAS / ADNOC innovation strategy (kaizen) we have implemented creative ideas.
During day to day maintenance activities we came across many break downs and repeated problems.
These repeated problems consume a lot of man hours and materials.
To rectify these problems we have implemented many innovative solutions that resulted in plant reliability and cost optimization by using internal resources.
Method: Un availability of Instrument & plant air during compressor shutdown in utility plant, Consume more energy while using portable air compressor. Consuming energy for the VRU compressor panel which was not in use. Pilot flare Auto Ignition system fail to operate due to corroded tubing's and junction box. Un availability of pump well pressure valves feedback indication due to repeated mechanical lever failure. Maintenance team exposure to sulphur toxic gases. Delay the LNG / LPG & paraffinic naphtha ships loading during SOV failure. More energy consumption to remove the Sulphur blockage from the loading line. Consuming more manpower and materials. Non availability of deluge valve during fire emergency. Fuel gas loss for Utility plants due to Boil off Gas compressor trip. Failure of Sulphur inlet valve.
Un availability of Instrument & plant air during compressor shutdown in utility plant, Consume more energy while using portable air compressor.
Consuming energy for the VRU compressor panel which was not in use.
Pilot flare Auto Ignition system fail to operate due to corroded tubing's and junction box.
Un availability of pump well pressure valves feedback indication due to repeated mechanical lever failure.
Maintenance team exposure to sulphur toxic gases.
Delay the LNG / LPG & paraffinic naphtha ships loading during SOV failure.
More energy consumption to remove the Sulphur blockage from the loading line.
Consuming more manpower and materials.
Non availability of deluge valve during fire emergency.
Fuel gas loss for Utility plants due to Boil off Gas compressor trip.
Failure of Sulphur inlet valve.
Results: Cost optimization of more than $ 1,800,000; enhance plant reliability and knowledge gained from accomplishing these projects. This knowledge will be shared with the audience.
Novel: The paper will encourage other Oil & Gas companies to implement innovative ideas to achieve maintenance and operational excellence.
Shekhar, Ravi (Zakum Development Company) | Naqbi, Amna Al (Zakum Development Company) | Obeta, Chukwudi (Zakum Development Company) | Ottinger, Gary (Zakum Development Company) | Herrmann, Rolf (Zakum Development Company) | Obara, Tomohiro (Zakum Development Company) | Almazrouei, Shamsa J. (Zakum Development Company) | Maqrami, Zinab N. Al (Zakum Development Company) | Neyadi, Abdulla Al (Zakum Development Company) | Edwards, Ewart (Zakum Development Company) | Shebl, Hesham (Zakum Development Company) | Li, Dachang (Zakum Development Company) | Shehhi, Budoor Hasan Al (Zakum Development Company) | Fazal, Ayub (Zakum Development Company)
Lower Cretaceous-aged carbonate sediments in a supergiant Middle Eastern oil field are characterized by extensive diagenetic overprints (e.g., dolomitized burrows, dissolution fabrics and fractures) which occur over areas of several kilometers. Due to the permeability contrast with respect to surrounding fine-grained matrix, the diagenetic features are believed to play an important role in reservoir fluid-flow, particularly as a major contributor to early water breakthrough observed in the field. Uncertainties associated with three-dimensional subsurface reservoir models can be mitigated by incorporating the results of detailed reservoir characterization studies. How these study findings are successfully and meaningfully implemented into the reservoir model can be a challenge and requires an integrated effort by reservoir geologists, modelers, and engineers.
This paper discusses a comprehensive reservoir characterization and modeling study conducted to capture the impact of diagenetic features on reservoir flow properties. A novel method was developed to map the spatial and stratigraphic distribution of these features from cores. Dolomitized burrows generally appear in core as randomly oriented features on a scale of cm to 10's of cm. They are characterized by grainier fill (packstone or grainstone), often dolomitized, within a background of muddier sediment (wackestone to packstone). Dissolution vugs are associated with algal rock type and can vary from few cms to 10's of cm. Fractures are generally layer specific and occur at the reservoir-dense boundaries. The origin of diagenetic processes and prediction of their occurrence is very difficult. However, the difference in texture and associated pore characteristics lead to heterogeneous porosity and permeability regimes that can have significant impact on sweep efficiency and recovery in oil fields that are subjected to waterflood.
A simplified, fit-for-purpose, rapidly updateable static model has been developed to ensure accurate stratigraphic and lateral distribution of diagenetic features based on cores, logs and dynamic data. Whole core data revealed potential guidance for assigning permeability in diagenetic features. A consistent SCAL framework has been developed to capture the relative effects of these diagenetic features on flow. After incorporation in the model, simulation results clearly shows water movement through these features and rapid water cut. This is in agreement to the field observation that has experienced earlier than expected water breakthrough and steady increases in water cut over time.
Refinery Delayed Coking units produce light components from the top of the fractionation section as one of the products. The extent of recovering LPG from this stream via the Gas Recovery Unit mainly depends on the costs involved in recovery.
Gas Recovery Units usually comprise of feed compression to a higher pressure followed by absorption with a solvent (i.e. naphtha) and a stripper column where the light components absorbed in the process stream are stripped. The rich solvent from the stripper bottom is then routed to a debutanizer column where LPG is separated. The recovered LPG and Fuel Gas undergo further amine treatment to meet H2S specifications.
The objective of this paper is to present the methodology applied to evaluate/optimize the different process schemes and main operating parameters of a Refinery Delayed Coking Gas Recovery Unit for optimum energy/cost effective LPG recovery.
The Delayed Coking Gas Recovery Unit has been simulated utilizing HYSYS® steady state simulation software linked to Aspen Process Economic Analyzer to evaluate the effect of different combinations of process schemes and operating parameters on the products recovery as well as equipment sizing and thus the capital cost, while estimating the required utilities and thus the operating cost.
Two main different process operating parameters have been studied: Absorber operating pressure Naphtha (Solvent) recycle ratio
Absorber operating pressure
Naphtha (Solvent) recycle ratio
Four different process schemes have been studied: Including both Recontactor and Presaturator Including Recontactor only Including Presaturator only Without both Recontactor and Presaturator
Including both Recontactor and Presaturator
Including Recontactor only
Including Presaturator only
Without both Recontactor and Presaturator
The Absorber operating pressure and the naphtha recycle ratio have major effect on the LPG recovery. Increasing either of the above parameters enhances the absorption and thus increases the LPG recovery on the other hand increases the utility consumption and thus the operating costs as well as increasing the equipment sizing and thus the capital cost.
The optimum operating parameters resulting in the higher net present value (NPV) and internal rate of return (i.e. higher economics parameters) was found to be an Absorber pressure of 22 bar (i.e. the pressure that can be achieved by 2 compression stages) and Naphtha recycle ratio of 0.42.
The optimum scheme was found to be that including both the Recontactor and Presaturator, although this scheme has extra equipment, however the addition of these equipment result in higher product recovery at lower Naphtha recycle ratio and thus result in savings in equipment sizing and thus capital cost as well as savings in the utility requirements (i.e. power and steam) and thus the operating costs.
Coker Gas Recovery Units are common in most refineries, although the design of this unit is conventional; however, this paper introduces new level of absorber operating pressure which has been proven to be economically attractive in recovering more LPG with reduced operating costs.
Veerakumar, Ukkirapandian (Abu Dhabi Gas Liquefaction Co Ltd) | Lallan, Sanjay Singh (Abu Dhabi Gas Liquefaction Co Ltd) | BaHamaish, Zeyad Nasser (Abu Dhabi Gas Liquefaction Co Ltd) | Abbas, Ahmad (Abu Dhabi Gas Liquefaction Co Ltd)
Objective of this project is to identify right technology and equipment for measurement of sulfur in natural gas products and adapt configuration changes of the system to avoid co-elution and for accurate measurement of individual sulfur compounds at ultralow level in the matrix of butane, propane and LNG. This involves standardization, validation and trials with plant samples.
There are different techniques by which sulfur impurities are measured. Some of them are lead acetate paper, air oxidation and combustion, potentiometric titration and gas chromatography (GC) with sulfur chemiluminescence detector (SCD) or Pulse Flame photometric detector (PFPD) or atomic emission detector (AED). We have worked extensively to identify, validate and adopt a new and advanced analytical technique for measurement of sulfur impurities in LNG and LPG products. As the level of quantification goes to ppb level it is very important that the measurement methods must be reliable, stable and acceptable to all customers.
GC with SCD has been identified as the best suitable one, for our products to determine individual sulfur compounds such as hydrogen sulfide, carbonyl sulfide, methyl, ethyl, propyl, butyl mercaptans and total sulfur. Several trails were performed with certified butane, propane and LNG standards at very low concentration levels and with real plant samples to validate and check for matrix effect and co-elution of COS with propane. The use of methyl mercaptan as calibration standard simplifies the calibration process as all sulfur compounds in our products have equimolar response in SCD.
The innovation and advancement made in the instrument configuration with right separation column, dual plasma burner and improved vacuum level by frequent maintenance of pumps improved the accuracy level of determination of sulfur compounds. The products from plant were tested and monitored for these sulfur impurities daily and their level was much lower than the specification limit delivering high quality products to customer.
Closely monitoring the quality of in-process and finished products from plant helped operators to make corrective actions immediately, in case there is increasing trend in these impurities or total sulfur. This has resulted in improvement of quality and their satisfaction giving more value for customers. Lower the level of sulfur impurities in our products, lower will be the environmental pollution through domestic usage or in power generation. It enhances the reputation of the company and generates more business and revenue.
The measurement of sulfur components is important for health, environmental and industrial (corrosion) protection. Environmental regulation require a gradually further decreasing emission of pollutants. The advancements developed have been documented and are suitable for monitoring quality and improvement. This is a valuable knowledge which will benefit other companies in oil and gas sector.
Chen, Hsieh (Aramco Services Company: Aramco Research Center-Boston) | Kmetz, Anthony A. (Aramco Services Company: Aramco Research Center-Boston) | Cox, Jason R. (Aramco Services Company: Aramco Research Center-Boston) | Poitzsch, Martin E. (Aramco Services Company: Aramco Research Center-Boston)
Full field inter well tracer programs have become more and more ubiquitous for effective reservoir surveillance. Novel tracer materials with much higher detectability and lower costs have been actively screened. One of the biggest challenges in deploying novel material types, however, is their elevated irreversible retention to reservoir rocks. Herein we benchmarked traditional inter well tracer chemicals and then the sensitivity of ever-increasing irreversible retention that might be associated with unconventional materials.
Using field-scale reservoir simulations with a Langmuir-type tracer irreversible retention model, we rigorously test the limits for tracer irreversible retention in order to have successful inter well tracer test (IWTT). Specifically, we studied the tracer breakthrough peak concentrations as a function of tracer irreversible retention as well as inter well spacing in synthetic waterflood patterns. Custom reservoir simulator functionalities were built to perform the simulations. Additionally, coreflood experiments on common oil field tracers were conducted to acquire independent irreversible retention values and compared to the modeling results.
For the reservoir simulations, we first tested the ideal tracer case with no irreversible retention and found perfect agreement with the standard Brigham-Smith model. We then tested for tracer breakthroughs with increasing irreversible retention values and found that the tracer breakthrough peak concentration drops off dramatically. With the consideration that the limit of detection (LOD) of contemporary analytical instruments are at the part per trillion (ppt) level, the simulation results suggested that the tracer irreversible retention should be less than 10 μg/g-rock (mass of adsorbed tracer / mass of rock) in order to have meaningful IWTT with a well spacing of 2000 ft and an injection tracer mass up to 100 kg. Finally, two field tests using fluorobenzoic acid (FBA) based tracers deployed in the highly saline and retentive carbonate reservoirs in Saudi Arabia were compared. The irreversible retention number of the FBA based tracers was estimated to be less than 5 μg/g-rock from the model. Corresponding coreflood experiments for FBA tracers in high temperature and salinity carbonate cores show 0 +/− 10 μg/g-rock irreversible retention number within error ranges, verifying the prediction of our simulation results.
This paper broadens the scope of the extensively used Brigham-Smith tracer behavior model by incorporating tracer irreversible retention effects. More accurate design and interpretation of inter well tracer tests may be achieved through the new insights presented. Better waterflood management can then be established because of the reduced uncertainties from the more precise tracer data. In addition, this study set an unambiguous standard for the tolerable irreversible retention limits for any new materials targeting inter well tracing applications.