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Results
Abstract Foamed fluids are commonly used in acidizing and fracturing applications to minimize formation damage, improve fluid recovery, and as diverting-agents. However, significant concerns with foamed fluids are poor stability and low viscosity. The study objectives include evaluating the commercially available surfactants’ foamability and stability when mixed with and without nanoparticles. The prepared foamed fluid characteristics such as rheology, morphology, stability, and proppant suspension were evaluated. Foam loop rheometer experiments were conducted at 1500 psi and 70% N2 quality to assess foam-stability and rheological properties. Foam decaying time was detected by half-life-time measurements (measuring foam-height as a function of time). Turbiscan was used to study the proppant settling using backscattering light. A high-resolution optical microscope was used to observe foam morphology and stability. The surfactant C-nanoparticles-based foamed fluid demonstrated stable foam with a high viscosity value that reached >110 cP at 100 S 77 °F and 70% N2 quality. Compared to the surfactant-based foamed fluid, combining the surfactant with nanoparticles as a foam-stabilizer increased the foam-half-life-time by nearly 35-75%. Foam bubbles size of surfactants A and B (with/without NPs) were large with an irregular shape and tended to rupture intermittently within 50 and 8 minutes, respectively. Bubbles average size of surfactant C (with/without NPs) based foams was small, and the count was higher than the foams of surfactants A and B. surfactant C (with/without NPs) based foams demonstrated bubbles with a spherical shape. Turbiscan stability index values of several surfactants-nanoparticles-based foamed fluids were almost comparable at 77 and 122 °F. Lastly, the foam fluids’ proppant settling velocity prepared with nanoparticles was lower than pure surfactant-based foams.
Abstract The first surfactant-based pilots can be traced back to the 1960s and since then almost a hundred field tests have taken place. Interestingly, almost half of these pilots have used an alkali (ASP) and the other half has not (SP). This reflects the current status of the industry which is divided along the same lines and over the same question: do surfactant-based processes require alkali or not? This paper proposes to address this question by providing explanations and discussing case studies. The paper will start by reminding the reader of the role of both surfactant and alkali and will review the pros and cons of alkali in terms of formulation performances, adsorption but also surface facilities and logistics. Several cases studies (lab and field) will be discussed to show when alkali can and cannot be used, and what solutions are available as alternatives to the use of alkali. Although alkali allows reducing both surfactant concentration and adsorption, it can also cause severe scaling and requires additional facilities including water softening; in addition, the large volumes of alkali required can cause logistical challenges. On the other hand, the main challenges of formulations without alkali is finding surfactants that can develop a low enough Interfacial Tension and low adsorption, or to find an acceptable adsorption mitigation strategy such as salinity gradient or adsorption inhibitors. In the early years of SP projects, very high surfactant concentrations were used (micellar process) and the process was not economic; as a result, alkali was seen as the only realistic solution. This appears to no longer be the case due to the developments of new surfactants. Although most projects in recent years have favoured the use of alkali, it seems that a trend towards SP is growing, with recent field projects in Kuwait, Oman, China and Russia favouring the SP solution. This paper will provide a discussion on the pros and cons of the use of alkali in surfactant-based processes. It will show that although using alkali has been a standard for many years it also entails severe surface issues such as scaling and requires additional capital for water softening and logistics. More importantly, recent developments in surfactants now seem to provide alkali-free solutions that can compete in terms of formulation performances. This now needs to be confirmed in the field.
- North America > United States > Texas (1.00)
- North America > Canada > Alberta (1.00)
- Asia > China (1.00)
- (7 more...)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline (0.93)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.47)
- North America > United States > Wyoming > Kiehl Field (0.99)
- North America > United States > Wyoming > Big Muddy Field (0.99)
- North America > United States > Texas > Tanner Field (0.99)
- (18 more...)
Abstract Guar and its derivatives are the most commonly used gelling agents for fracturing fluids. At high temperature, higher polymer loadings are required to maintain sufficient viscosity for proper proppant carry and creating the fracture geometry. To minimize fracturing fluids damage and optimize fracture conductivity, it is necessary to design a fluid that is easy to clean up by ensuring proper breaking and sufficiently low surface tension for flow back. Therefore, breakers and surfactants must be carefully selected and optimally dosed to ensure the success of fracturing treatments. In this study, two fracturing fluids were evaluated for moderate to high temperature applications with a focus on post-treatment cleanup efficiency. The first is a guar-based fluid with a borate crosslinker evaluated at 280°F and the second is a CMHPG-based fluid with a zirconate crosslinker evaluated at 320°F. The shear viscosities of both fluids were tested with a live sodium bromate breaker, a polymer encapsulated ammonium persulfate breaker and a dual breaker system combining the two breakers. Different anionic and nonionic surfactant chemistries (aminosulfonic acid and alcohol based) were investigated by measuring surface tension of the surfactant solutions at different concentrations. The compatibility of the surfactants with other fracturing fluid additives and their adsorption in Berea sandstone was also investigated. Finally, the damage caused by leak-off for each fracturing fluid was simulated by using coreflooding experiments and Berea sandstone core plugs. Lab results showed the guar and CMHPG fluids maintained sufficient viscosity for the first two hours at baseline, respectively. The encapsulated breaker proved to be effective in delaying the breaking of the fracturing fluids. The dual breaker system was the most effective and the loading was optimized for each tested temperature to provide the desired viscosity profile. Two of the examined surfactants were effective in lowering surface tension (below 30 dyne/cm) and were stable for all tested temperatures. The guar broken fluid showed better regained permeability (up to 94%) when compared to the CMHPG (up to 53%) fluid for Berea sandstone. This paper outlines a methodical approach to selecting and optimizing fracturing fluid chemical additives for better post-treatment cleanup and subsequent well productivity.
- North America > United States > West Virginia (0.66)
- North America > United States > Pennsylvania (0.66)
- North America > United States > Ohio (0.66)
- North America > United States > Kentucky (0.66)
Manganese Assisted Waterflooding Processes for Enhanced Oil Recovery in Carbonates
Alghamdi, Amani (EXPEC Advanced Research Center, Saudi Aramco) | Salah, Saleh (EXPEC Advanced Research Center, Saudi Aramco) | Otaibi, Mohammed (EXPEC Advanced Research Center, Saudi Aramco) | Ayirala, Subhash (EXPEC Advanced Research Center, Saudi Aramco) | Yousef, Ali (EXPEC Advanced Research Center, Saudi Aramco)
Abstract Modifying the wettability of carbonate formations through divalent foreign metal incorporation can become a cost-effective practical method for enhanced oil recovery (EOR) applications. The addition of manganese ions to both high salinity water (HSW) and tailored SmartWater at dilute concentrations is exploited in this study to maximize the interfacial potential and promote water-wet conditions in carbonate reservoirs. In this experimental investigation, the impact of manganese ions on zeta-potentials at calcite/brine and crude oil/brine interfaces is first determined by measuring zeta-potentials in calcite suspensions and oil emulsions. Two different water chemistries representative of HSW (~60,000 ppm TDS) and a low salinity tailored SmartWater (~6,000 ppm TDS) were used. The measurements were then extended to carbonate rocks and reservoir cores by performing contact angle and spontaneous imbibition tests at reservoir conditions. The oil-water interfacial tensions are also measured to understand the interactions of manganese ions at the oil/brine interface. The zeta potential results showed a positive consistent trend, with the addition of 100-1,000 ppm of Mn ions in the form of MnSO4 to the high salinity water, to impact the wetting transition towards water-wet conditions in carbonates. The addition of Mn ions at a concentration of 100-1,000 ppm to HSW enhanced the electrokinetic interactions to favorably alter surface charges at both oil/brine and calcite/brine interfaces. These findings based on eletrokinetic interactions demonstrated good agreement with contact angle data wherein manganese ions in HSW were able to drastically decrease the contact angles from 156 to 88°. Conversely, insignificant changes in oil-water interfacial tensions were observed due to manganese ions. The manganese assisted spontaneous imbibition oil recoveries were increased by about 10% in HSW. Mn ions showed the ability to increase the negative potentials at both calcite/brine and oil/brine interfaces. The obvious trend of such enhanced electrical potential due to Mn addition at the calcite interface supports the claim that Mn selectively gets incorporated into the calcite crystal to modify its surface chemistry. This is expected to increase the surface charges of same polarity at the two opposing interfaces and promote the electrostatic repulsion to inherently change the surface preference towards water-wet conditions. This work for the first time identified the favorable impact of incorporating Mn ions under optimized conditions to enhance the wetting transition in carbonate reservoirs. Such new knowledge gained from this experimental study highlights the practical significance of Mn ions as cheap and sustainable wettability modifiers for EOR applications in carbonate reservoirs.
- Geology > Mineral > Carbonate Mineral > Calcite (1.00)
- Geology > Rock Type > Sedimentary Rock (0.35)
Abstract Natural gas is sampled or produced throughout the lifespan of a field, including geochemical surface survey, mud gas logging, formation and well testing, and production. Detecting and measuring gas is a common practice in many upstream operations, providing gas composition and isotope data for multiple purposes, such as gas show, petroleum system analysis, fluid characterization, and production monitoring. Onsite gas analysis is usually conducted within a mud gas unit, which is operationally unavailable after drilling. Gas samples need be taken from the field and shipped back to laboratory for gas chromatography and isotope-ratio mass spectrometry analyses. Results take a considerable time and lack the resolution needed to fully characterize the heterogeneity and dynamics of fluids within the reservoir. We are developing and testing advanced sensing technology to move gas composition and isotope analyses to field for near real-time and onsite fluid characterization and monitoring. We have developed a novel QEPAS (quartz-enhanced photoacoustic spectroscopy) sensor system, employing a single interband cascade laser, to measure concentrations of methane (C1), ethane (C2), and propane (C3) in gas phase. The quartz fork detection module, laser driver, and interface are integrated as a small sensing box. The sensor, sample preparation enclosures and a computer are mounted in a rack as a gas analyzer prototype for the bench testing for oil industry application. Software is designed for monitoring sample preparation, collecting data, calibration and continuous reporting sample pressure and concentration data. The sensor achieved an ultimate detection limit of 90 ppb (parts per billion), 7 ppb and 3 ppm (parts per million) for C1, C2, and C3, respectively, for one second integration time. The detection limit for C2 made a record for QEPAS technique, and measuring C3 added a new capability to the technique. However, the linearity of the QEPAS sensing were previously reported in the range of 0 to 1000 ppm, which is mainly for trace gas detection. In the study, the prototype was separately tested on standard C1, C2, and C3 with different concentrations diluted in dry nitrogen (N2). Good linearity was obtained for all single components and the ranges of linearity were expanded to their typical concentrations (per cent, %) in natural gas samples from oil and gas fields. The testing on the C1-C2 mixtures confirms that accurate C1 and C2 concentrations in % level can be achieved by the prototype. The testing results on C1-C2-C3 mixtures demonstrate the capability of simultaneous detection of three hydrocarbon components and the probability to determine their precise concentrations by QEPAS sensing. This advancement of simultaneous measuring C1, C2 and C3 concentrations, with previously demonstrated capability for hydrogen sulfide (H2S) and carbon dioxide (CO2) and potential to analyze carbon isotopes (C/C), promotes QEPAS as a prominent optical technology for gas detection and chemical analysis. The capability of measuring multiple gas components and the advantages in small sensor size, high sensitivity, quick analysis, and continuous sensing (monitoring) open the way to use QEPAS technique for in-situ and real-time gas sensing in oil industry. The iterations of QEPAS sensor might be applied in geochemical survey, on-site fluid characterization, time-lapse monitoring of production, and gas linkage detection in the oil industry.
- Asia > Middle East (0.47)
- North America > United States (0.46)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Mineral > Silicate > Tectosilicate > Quartz (0.47)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Geochemical characterization (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
Application of a Novel Ecofriendly Okra Powder as Fluid Loss Controller in Water Based Drilling Fluids
Murtaza, Mobeen (King Fahd University of Petroleum & Minerals) | Tariq, Zeeshan (King Fahd University of Petroleum & Minerals) | Zhou, Xianmin (King Fahd University of Petroleum & Minerals) | Al Sheri, Dhafer (King Fahd University of Petroleum & Minerals) | Mahmoud, Muhammad (King Fahd University of Petroleum & Minerals) | Kamal, Shahzad (King Fahd University of Petroleum & Minerals)
Abstract Saudi Arabian based companies are spending many millions of dollars a year on import of drilling mud additives to meet the drilling industry demand. To cut the imported materials, locally available materials are preferable. Out of many drilling fluid additives, a single locally available additive such as fluid loss can save millions of dollars a year. The cost and locally available raw material justify the development of drilling fluid additives in the Kingdom of Saudi Arabia. In other aspect, local development provides many benefits to the Kingdom including industrial growth, technology ownership and new job opportunities. Okra (Hibiscus esculents) is widely used as a thickener and viscosifier in medical and food industries due to its low cost, availability, longer shelf life, and high thermal tolerance. In addition to that, it is environment friendly and available in abundance locally in Kingdom of Saudi Arabia. The composition of Okra powder was diagnosed by X-ray fluorescence (XRF) and Fourier-transform infrared spectroscopy (FTIR). The thermal stability of Okra was tested using thermal gravimetric analysis (TGA). The Okra powder was mixed in various concentrations such as (1, 2 and 3) grams in 350ml of water based drilling fluid (WBDF). The performance of Okra contained drilling fluids was compared with starch-based drilling fluid. The addition of Okra reduced fluid loss in different proportions at different concentrations. For instance, drilling fluid with 3g Okra concentration had 42% lower fluid loss as compared to the base fluid. The cake thickness was reduced upon the addition of Okra. The low fluid loss and thin filter cake make Okra a useful solution as a fluid loss controller in WBDFs. The addition of Okra powder also increased the viscosity and gel strength of the WBDFs. TGA analysis of Okra powder showed that it has strong thermal stability as compared to starch. Overall, the experimental results suggest that Okra mixed drilling fluids can be used as an alternate solution to starch mixed drilling fluids.
Abstract This paper presents an unparalleled engineering assessment conducted to evaluate the feasibility of pre-investing in O2 enrichment technology, with the purpose of increasing the processing capacities of conventional air-based sulfur recovery units (SRUs). Ultimately, the goal is to minimize the overall number of required SRUs for a greenfield gas plant and, consequently, capture a significant cost-avoidance opportunity. The technology review revealed that a high-level O2 enrichment can double the processing capacity of air-based SRU, depending on the H2S content in acid gas. As H2S mole fraction in feed increases, the debottlenecking capability increases. For the project under assessment, the processing capacity of air-based SRUs showed a maximum increase of 80%. On the contrary, operating with high O2 levels, will elevate SRU reaction furnace temperature, and mandates installing high-intensity burners, along with special control and ESD functions, to manage potential risk and ensure safe operation. Additionally, the liquid handling section of SRUs (condensers, collection vessels, degassing vessels, sulfur storage tanks) should be enlarged to accommodate more sulfur production. Typically, the enriched oxygen can be supplied from air separation units (ASUs), which entails significant capital cost. Apart from these special design considerations, there are several advantages for adopting this technology. Oxygen enrichment removes significant nitrogen volumes, which reduces loads on Claus, tail gas treatment, and thermal oxidizer units. Hence, lower capital cost for new plants is acquired due to equipment size reduction. In addition, higher HP steam production and less fuel gas consumption are achieved. Conventionally, O2 enrichment technology is employed in the initial design stage or used to retrofit operating SRUs facilities. However, it is unique to consider O2 enrichment-design requirements as part of new air-based SRUs design for phased program development. The objective is to enable smooth transition to fully O2 enrichment operated SRUs at a later phase of the project without the need for any design modification. This exceptional pre-investment strategy has resulted into reducing the required number of SRUs at phase II from eight to five units; and accordingly, a significant cost avoidance was captured.
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (1.00)
- Facilities Design, Construction and Operation > Processing Systems and Design > Gas processing (1.00)
Development of Novel Shale Swelling Inhibitors Using Hydrophobic Ionic Liquids and Gemini Surfactants for Water-Based Drilling Fluids
Khan, Rizwan Ahmed (Department of Petroleum Engineering, KFUPM) | Murtaza, Mobeen (Department of Petroleum Engineering, KFUPM) | Ahmad, Hafiz Mudaser (Department of Chemical, Polymer & Composite Materials Engineering, UET) | Abdulraheem, Abdulazeez (Department of Petroleum Engineering, KFUPM) | Kamal, Muhammad Shahzad (Center for Integrative Petroleum Research, KFUPM) | Mahmoud, Mohamed (Department of Petroleum Engineering, KFUPM)
Abstract In the last decade, hydrophilic Ionic liquids have been emerged as an additive in drilling fluids for clay swelling inhibition. However, the application of hydrophobic Ionic liquids as a clay swelling inhibitor have not been investigated. In this study, the combination of hydrophobic Ionic liquids and Gemini surfactant were studied to evaluate the inhibition performance. The novel combination of hydrophobic ionic liquid (Trihexyltetradecyl phosphonium bis(2,4,4-trimethyl pentyl) phosphinate) and cationic gemini surfactant (GB) was prepared by mixing various concentrations of both chemicals and then preparing water based drilling fluid using other drilling fluid additives such as rheological modifier, filtration control agent, and pH control agent. The wettability of sodium bentonite was determined by contact angle with different concentrations of combined solution. Some other experiments such as linear swelling, capillary suction test (CST) and bentonite swell index were performed to study the inhibition performance of ionic liquid. Different concentrations of novel combined ionic liquid and gemini surfactant were used to prepare the drilling fluids ranging from (0.1 to 0.5 wt.%), and their performances were compared with the base drilling fluid. The wettability results showed that novel drilling fluid having 0.1% Tpb-P - 0.5% GB wt.% concentration has a maximum contact angle indicating the highly hydrophobic surface. The linear swelling was evaluated over the time of 24 hours, and least swelling of bentonite was noticed with 0.1% Tpb-P - 0.5% GB wt.% combined solution compared to linear swelling in deionized water. Furthermore, the results of CST also suggested the improved performance of novel solution at 0.1% Tpb-P - 0.1% GB concentration. The novel combination The novel combination of hydrophobic ionic liquids and gemini surfactant has been used to formulate the drilling fluid for high temperature applications to modify the wettability and hydration properties of clay. The use of novel combined ionic liquid and gemini surfactant improves the borehole stability by adjusting the clay surface and resulted in upgraded wellbore stability.
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.55)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
A Successful Field Application of Polymer Gel for Water Shutoff in a Fractured Tight Sandstone Reservoir
Wu, Qianhui (China University of Petroleum East China) | Ge, Jijiang (China University of Petroleum East China) | Ding, Lei (Texas A&M University at Qatar) | Wei, Kaipeng (Sinopec North China Petroleum Bureau, Zhengzhou) | Liu, Yuelong (Sinopec North China Petroleum Bureau, Zhengzhou) | Deng, Xuefeng (Sinopec North China Petroleum Bureau, Zhengzhou)
Abstract The wide existence of fractures makes conformance control by polymer gels more challenging in water-flooded oil reservoirs. Selection of an applicable gel system and design of an intelligent approach for gel treatment are key components for a successful field application. Moreover, selecting the candidate wells and determining the injection volume of gel are also critical to the success of gel treatments. A gel system with adjustable polymer concentrations was applied for conformance control in fractured tight sandstone reservoir, and notably, less than 5% of syneresis was detected after aging for one year at reservoir condition. The viscosity and the gelation time of this gel system can be adjusted according to the targeted reservoir conditions. The pilot test was conducted in Huabei oilfield (China), and the oil recovery after water flooding was only about 20% original oil in place (OOIP). With further exploitation of the oil field, the majority of the reservoir has suffered from poor sweep efficiency and extremely high water cuts. To characterize the distribution of fractures, the seismic coherence cube was utilized. In addition, the pressure transient test, interwell tracer test and the injection-production data were used collaboratively to determine the volume of fractures in the reservoir. The option of gel formulation and the determination of operational parameters are mainly based on the wellhead pressure. According to the seismic coherence cube, the zone of candidate well group shows a weak coherence state, indicating that numerous fractures exist. Furthermore, there is good continuity between the candidate injection well and the production well. According to the pressure transient test, the volume of re-open fracture is about 1730.9 m, while the volume of micro-fracture is about 4839.4 m. Comparably, based on the interwell tracer test, the estimated volume of fractures is approximately 3219.7 m. Consequently, the designed volume of gel for treatment is 1500.0 m in total. The properties of gel slugs were carefully designed, which was tailored to the specific wellbore conditions and formation characteristics. Three months after the gel treatment, the average oil production was increased from 0.36 t/d to 0.9 t/d, and the water cut was decreased from 95.77% to 88.7%. The improved oil production was still benefited from this gel treatment after one year. This study provides a comprehensive approach, from optimization of gel formulation, followed by selection of candidate wells, to calculation of the injected volume, to design the viable operational parameters, for gel treatment field application in fractured reservoirs. It shows that, besides a gel system with superior properties, a suitable injected volume of gel may enhance the chance of success for gel treatments.
- North America (1.00)
- Asia > China > Hebei Province (0.25)
- North America > Canada > Saskatchewan > Williston Basin > Midale Field > Midale Formation (0.99)
- North America > Canada > Saskatchewan > Williston Basin > Midale Field > Charles Formation (0.99)
- Asia > China > Hebei > Bohai Basin > Huabei Field (0.99)
Abstract Gelled acid systems based upon gelation of hydrochloric acid (HCl) are used widely in acid stimulation treatments to prevent fluid leak-off into the high permeable zones of a reservoir. The gelled-up fluid system helps retard the acid reaction to allow deeper acid penetration for hydrocarbon productivity enhancement. Conventional in-situ crosslinked gelled acid systems are made up of polyacrylamide gelling agent, iron-based crosslinker, and a breaker chemical in addition to other additives, with the acid as the base fluid. The polymer-based systems can lead to damage to formation due to a variety of reasons including unbroken polymer residue. Additionally, the iron-based crosslinker systems can lead to scaling or precipitation after the acid reacts with the formation, resulting in formation damage and lowering of hydrocarbon productivity. In this paper, we showcase a new nanoparticles-based gelled acid system that does not contain any polymer or iron-based crosslinker that can potentially damage the formation. It comprises nanoparticles, a gelation activator, acidizing treatment additives along with HCl. The new in-situ gelled acid system has low viscosity at surface making it easy to pump. With increase in the temperature and as the acid spends there is a viscosity increase. The viscosification and eventual gelation of the new system can be achieved as the acid reacts with a carbonate formation. As the acid further reacts and continues to spend, the gel demonstrates reduction of viscosity. This assists in a better cleanup post the acidizing treatment. Various experimental techniques were used to highlight the development of the nanoparticle-based acid diversion fluid. The gelation properties of the acid system, as a function of acid strength and temperature, are investigated. Static and dynamic gelation studies as a function of time, temperature and pH are reported. It is demonstrated that the viscosification property is a function of pH and the gelation occurs in a pH widow from 1 to 5 pH units. The gelation performance of the new system is evaluated at temperatures up to 300°F. The effect of different types of surface modification chemistries on the gelation properties is investigated. It is also shown that the gelation and viscosity reduction is entirely a pH dependent phenomenon and does not require any additional breaker chemistry; and therefore provides more control over the system performance. The new gelled acid system overcomes the inherent challenges faced by conventional in-situ crosslinked gelled acid systems; as it is based upon nanoparticles making it less prone to formation damage as compared to a crosslinked polymer-based system.