Salt-tolerant cationic friction reducers (FRs) have been successfully used in up to 100% high total dissolved solids (TDS) produced water for hydraulic fracturing applications. Cationic FRs, however, may not be compatible with formation rocks that contain quartz or clay that is typically negatively charged under normal pH. In this study, a new cationic FR formulation is introduced that does not appear to alter rock wettability and that releases a clay stabilizing agent over time under downhole conditions.
Flow loop, capillary suction time (CST), turbidity, and zeta potential (ZP) tests are conducted to demonstrate the benefits of using a multifunctional FR that tends to have minimal formation damage toward formation rocks. Flow loop tests qualify the FR as a robust polymer that is salt-tolerant and enables up to 100% re-use of produced water on location. Both CST and turbidity evaluates the efficacy of the clay stabilizing agent that is released from the FR under downhole conditions. ZP measures the surface charge on the rock's surface and determines whether or not significant wettability alteration occurs in the presence of this FR.
Flow loop results verify that the new FR is extremely salt-tolerant up to 300,000 ppm TDS, which was further demonstrated in the Marcellus Shale formation. Both CST and turbidity results suggest that the performance of the clay stabilizer is equivalent to that of a 4% KCl solution, a common temporary clay stabilizer. ZP indicates that the FR became predominantly negatively charged after releasing the clay stabilizing agent, thereby having minimal effect on the original rock wettability.
Satti, Rajani (Baker Hughes, a GE company) | White, Ryan (Baker Hughes, a GE company) | Ochsner, Darren (Baker Hughes, a GE company) | Sampson, Tim (Baker Hughes, a GE company) | Zuklic, Stephen (Baker Hughes, a GE company) | Geerts, Shaun (Owen Oil Tools)
As the industry looks forward to increasing operational efficiencies and maximizing productivity, there has been increasing interest in perforating systems that can combine perforating and well stimulation in a single operation. For this reason, propellants have a unique place in the perforating community as a stimulation/enhancement tool that can significantly improve productivity and lower operator costs. However, in complex well completions (high angle, doglegs or long horizontal wells), friction ignition and other concerns with traditional propellant methods have led to the advent of a new enhanced perforating system, whereby the energetic materials are deployed within the gun body, requiring specific charge performance, and in specially designed carriers.
The enhanced perforating system has been successfully deployed in the field. In the interest of conducting a quantitative evaluation, this study is focused on developing and demonstrating a fit-for-purpose flow laboratory apparatus to evaluate the benefits of the enhanced perforating system using standard API-RP 19B Section-IV procedures. The experimental apparatus was designed to closely represent the actual gun system, whereby the detonation of the perforating charge initiates a complex, sequentially burning reaction of the energetic material that generates a high-pressure gas pulse. A comprehensive testing program in Berea sandstone using shaped charges in conjunction with these energetic propellant materials at representative downhole conditions was conducted.
The analysis from the experimental tests was not limited to standard measurements, but also included advanced interpretation techniques involving high-speed transient pressure analysis, 3D computerized tomography and productivity analysis. Preliminary analysis of the test data showed promising trends with respect to increased peak pressure, improved clean-up and extended tip-region around the perforation tunnel. Furthermore, the HSE aspects of this enhanced system from a laboratory standpoint were also investigated.
In summary, the above study presents a laboratory study and quantitative evaluation of an enhanced perforating system that combines shaped charges and energetic materials. This system has been field proven to assist in pre-frac treatment. The benefits of the system can be further realized in conjunction with frac-optimized perforating systems, whereby frac-treatments are optimized to enhance productivity.
Shah, S. (University of Oklahoma) | Asadi, M. (Fritz Industries) | Wheeler, R. (Baker Hughes a GE cmpany) | Brannon, H. (Sun Drilling Producrts) | Kakadjian, S. (Keane Frac) | Ainley, B. (ConocoPhillips) | Chen, Y. (Schlumberger) | McElfresh, P. (Consultant) | Ghalambor, A. (Oil Center Research Intl) | Kaufman, P. (Consultant) | Archacki, D. (Shrieve Chemical Products)
Friction reducers have been an integral part of the oil and gas industry for many years. They possess very unique properties of reducing friction pressure associated with the flow of fluid in tubulars. Friction pressure loss or hydraulic characteristics of friction reducers depend greatly on how they are tested and evaluated in the laboratory. Today, there is no standard procedure for their evaluation. American Petroleum Institute (API) oversees the development and publication of industry standard practices for various fluids and materials. Recognizing the need for a standard testing procedure for friction reducers, a Committee made up of members from industry and academia was formed and charged to develop a document outlining the standard procedure.
Round-robin tests were conducted by four industry organizations and one academic institution, employing their in-house flow loops and were requested to report the results. Tests were to conduct friction pressure measurements of friction reducers, and to develop and deliver to the industry a standard procedure and method to measure and analyze friction reducers data in straight pipes. The test fluids chosen were two friction reducers: one anionic and the other cationic. Water data were also gathered as base line. Same fluid samples were submitted to all laboratories. The calibration procedure and fluid testing procedure was developed and distributed to all involved in fluid testing. The analysis for data reduction and for reporting results was also developed and distributed to all.
It was found that the calibration procedure was more critical than originally thought. The determination of internal diameter of the circular tube is the most important parameter that influences the friction pressure loss results greatly. In this paper, the details of various flow loops, calibration procedure, data analysis procedure, and results obtained with water as base line and two friction reducers are presented and discussed. A standard procedure for testing and evaluating friction reducers for their friction loss properties is outlined.
Following this standard procedure and carefully performing the testing with friction reducers will yield very similar results among various laboratories in the industry. This will make it easy when comparing the performance of friction reducers for their friction loss properties from different organizations.
Jøntvedt, Eirik (Total E&P Norge) | Fjeldheim, Mikkel (Total E&P Norge) | Løchen, Johan (Cabot Specialty Fluids) | Howard, Siv (Cabot Specialty Fluids) | Leon, Stuart (Cabot Specialty Fluids) | Busengdal, Christian (Cabot Specialty Fluids) | Richard Gyland, Knud (M-I SWACO, Schlumberger Norge)
This paper summarizes the experiences of Total E&P's first use ever of a low-solids cesium formate reservoir drill-in and screen-running fluid. The unique 2.07 SG formate brine-based mud system was used by Total E&P Norge as reservoir drill-in fluid (RDF) and screen running fluid in a Brent high permeability, high pressure gas well No. 4, in the Martin Linge field on the Norwegian Continental shelf. The fourth gas well was the first Martin Linge well completed openhole with 250-micron stand-alone sand screens (SAS). The previous Martin Linge gas wells were drilled and completed with 230-micron expandable sand screens (ESS), using non aqueous based mud (NABM).
The low-solids cesium formate fluid was chosen for its known ability to produce easily through sand screens. The final fluid formulation, which consisted of concentrated cesium/potassium formate brine, included xanthan gum, high-temperature modified starch, and calcium carbonate bridging material, successfully underwent a series of qualification testing, including fluid loss control, rheology, formation damage, and production screen testing (PST).
The main benefits seen with the formate fluid system compared with the solids laden NABM fluid systems when drilling the 8½-in. reservoir sections were significantly higher rate of penetration (ROP) with lower weight on bit (WOB), better drilling dynamics, significantly lower (0.016 SG) equivalent circulating density (ECD), 35% lower stand pipe pressure (SPP), and 5°C lower bottom hole circulating temperature (BHCT).
The drilling fluid properties were easily maintained within specifications. Compared with the NABM, the main benefits were improved rheology, lower solids content, and much thinner, non-elastic filter cake.
Improved wellbore stability was experienced for the well No. 4 compared with previous reservoir sections, and there was no indication of poor hole cleaning during drilling, tripping, or during lower completion operations, and no stuck-pipe incidents were experienced. In the previous reservoir sections, a stuck-pipe incident had been experienced in a coal section, requiring a sidetrack to be drilled.
The only performance issue with the formate fluid was its higher mechanical friction, which caused a 25% increase in drilling torque compared with the previous sections drilled with NABM.
A short cleanup of the well was conducted before the well was suspended. Despite the shorter cleanup time of the well No. 4 compared with the previous wells, the well's stipulated productivity index (PI) was twice as high. The pressure build-up response indicated full connection to the reservoir and no indication of partial plugging, which had been the problem during the cleanup attempts of the previous gas wells.
Disregarding the significant increase in fluid cost compared to the previous reservoir sections that were drilled and completed with NABM, well No. 4 was a technical and commercial success based upon drilling and tripping operations, completion operations, and cleanup results.
The current trends to re-evaluate the need for traditional clay control additives and the interest in increasing hydrocarbon production from secondary fracture networks are leading to the use of more appropriate fluid compositions. Additives historically used to dehydrate or exchange interlayer cations in water-reactive phyllosilicates introduce instability in the reservoir matrix and have been used in shale reservoirs without thorough assessments of potential formation damage. Framing the need for clay control in these reservoirs solely on the need to control water-reactive clays led naturally to the removal of clay control additives from fluids during the recent downturn. While justified from a cost perspective, these simplified fluids were introduced without assessments of the impact of near colloidal (10-40um diameter) fines generation. Completion experts who realize the formation damage risk of fines generation recognized these problems.
This paper updates the industry on an approach to proportion clay control and shale stabilization with fluid design better aligned to reservoir mineralogy and the stress introduced on the reservoir during hydraulic fracturing. The paper reports swelling clay control and near colloidal fines evaluations from four world class unconventional oil & gas reservoirs in North America. Reproducible fundamental trends in CST and near-colloidal fines generation data are correlated to clay control additive type and use of oxidative breaker. Additionally, this new test method has the potential to be easily and commercially viable for rapid field evaluation to assess formation damage due to fines generation.
It was recently shown that anisotropic wormhole networks may arise from the acidizing of anisotropic carbonates. In openhole or cased and densely perforated completions, where in isotropic formations the wormhole network would be expected to be radial around the well, the actual stimulated region may be elliptical in anisotropic formations. Analogously, in completions where the limited entry technique is used, the wormhole network is expected to be spherical in isotropic formations, but it may actually be ellipsoidal in anisotropic formations. That has an impact on the well performance and should be taken into account when designing the acidizing treatment and the completion. At the same time, the use of a limited entry technique may result in better stimulation coverage and also longer wormholes, but it may also result in a partial completion skin factor, impairing the productivity from the stimulated well. This should be taken into account when estimating the stimulated well productivity.
In this study two main topics are analyzed: the impact of wormhole network anisotropy and the impact of a limited entry completion. Both radial and spherical wormhole propagation patterns are considered, to be applied in both openhole and limited entry completions. The differences in well performance is studied for each case, and analytical equations for the skin factor resulting from each scenario are presented.
The anisotropic wormhole networks are obtained from numerical simulations using the averaged continuum model, and the results are validated with experimental data. The analysis of the well performance is made through simulation of the flow in the reservoir with the different stimulated regions.
The results show that for highly anisotropic formations the wormhole network anisotropy may have a great impact on the acidized well performance and this should be taken into account in the acidizing treatment design. It was observed that the anisotropic wormhole networks present lower productivity than equally sized isotropic stimulated regions. Hence, equations like Hawkins formula should not be used for estimating the skin factor from anisotropic wormhole networks, and the equations proposed in this work should be used instead.
Specifically, the impact of anisotropic wormhole networks is large when the limited entry technique is used. It is shown that for this type of completion there is an optimum stimulation coverage of about 60 to 70%, and the perforation density required to obtain for a given acid volume depends strongly on the wormholes' anisotropy. The skin factor equations proposed in this work for the stimulation with limited entry completion should be used for obtaining the optimum perforation density for a given scenario.
Fattahpour, V. (RGL Reservoir Management) | Mahmoudi, M. (RGL Reservoir Management) | Wang, C. (University of Alberta) | Kotb, O. (University of Alberta) | Roostaei, M. (University of Alberta) | Nouri, A. (University of Alberta) | Fermaniuk, B. (RGL Reservoir Management) | Sauve, A. (RGL Reservoir Management) | Sutton, C. (RGL Reservoir Management)
Stand-alone sand screen (SAS) is proven to be effective for sand control in unconsolidated sands in thermal wells. The characteristic design parameter to specify SAS is the aperture size, while the Open to Flow Area (OFA) is chosen to balance between the mechanical integrity of the screen, the completion cost, and the plugging risk. The objective of this study is to compare the performance of common SAS types for a certain geological condition.
A series of three-phase large-scale sand retention tests (SRTs) is performed on slotted liner, wire-wrapped screen, and punched screen coupons. The tests are performed using two common representative PSDs of the McMurray Formation. The test matrix includes the common aperture sizes and OFA for each screen and PSD based on the current best practices in the industry. The test procedure is designed to mimic the near wellbore flow velocities, with three-phase flow ranging from 0%-100% water cut and produced gas-oil ratio ranging from 0-277 scf/bbl. The gas flow was supposed to simulate the steam breakthrough incidents. Live measurements are obtained of the sanding amount and pressure drops along the sand-pack and across the screen. Screen plugging is assessed after the completion of each test.
The sanding and flow performance are shown to be a function of the aperture size, PSD, near-wellbore flow velocities, and the water cut. In low fluid flow rates, all the screen types show minimal pressure drops and perform similarly. As near-wellbore velocities increase or gas flow occurs, pressure drops show a significant increase for all devices. Results show OFA, aperture size, and screen type affect the pressure drop and sanding. In all cases, the produced sand in three-phase flow is the determining design parameter for the upper-bound acceptable aperture. The gas flow is observed to accompany large amounts of sanding for larger aperture sizes. Further, test results indicate high pressure drops for three-phase flow conditions. Test results reveal the complexity of the interaction between different design parameters, which affect the sand and flow performance, hence, necessitating an SRT test for each specific case.
This paper presents the results of physical model testing of different standalone screens in terms of flow performance and sand control. This will help to identify the main factors that influence the performance of each specific screen type and develop the rationale for the screen type selection in new developments.
Core flood tests are regarded as critical to qualification and optimization of scale inhibitors (SIs) deployed in "squeeze" mode, to assess both formation damage and chemical performance. However, the different test protocols commonly adopted can have significant impact on the outcome of both these aspects. Generally, SI core flood tests are designed to obtain both pieces of information from a single flood, often compromising the optimal testing of either or leading to chemical performance aspects being favoured over formation damage or
Recent reports have illustrated how differences in test protocols can impact chemical performance results for clastic sandstones; the work presented in this current paper examines similar challenges in tight carbonate systems, such as those exhibiting both matrix and fracture flow. It demonstrates the importance of conducting core flood tests under representative conditions for these more reactive substrates in order to qualify chemicals appropriatelysuch that upscaling to the field case can be accurately achieved.
A suite of core flood tests were conducted on outcropcarbonate cores under matrix- and fracture-dominated flow conditions (simulating both macro and micro fractures), which allowed examination of chemical behaviour under different application conditions, thus highlighting differences in chemical-retention properties and associated treatment lifetimes as well as in formation damage assessment. This paper examines results from fractured carbonate core tests, which were designed to examine SI interaction and retention where chemical transport is dominated by diffusion, and compares these withsystems where transport is dominated by advective flow in the rock matrix. The overall aim was to examine the impact that core test design can have on the results observed and to discuss the consequences of different test approaches for chemical qualification. In summary, results show that different fracture apertures and flow conditions (matrix
Azari, Mehdi (Halliburton) | Hadibeik, Hamid (Halliburton) | Ramakrishna, Sandeep (Halliburton) | Bakiri, Kamal (Sonatrach) | Imouloudene, Abdellaziz (Sonatrach) | Ghalambor, Ali (Oil Center Research International)
This paper discusses the causes of performance failure of a well in the Hassi Messaoud field in Algeria that was fracture stimulated but did not achieve the expected production increase, and it discusses alternative methods to increase well production by integrating geology and petrophysics with production and well-test data.
The well was perforated in sand B and in the upper section of sand C. It was initially tested at 5.07 m3/h (765 B/D), but within three months, production declined to 1.99 m3/h (300 B/D). Early studies suggested that the rapid decline was probably caused by near-wellbore formation damage during drilling. A fracturing program was designed to help remove well damage and restore flow capacity; however, negligible production increase was observed following the hydraulic fracturing. Initially, damage on the fracture face and uncleaned fracturing fluid were the suspected causes of the ineffective fracture stimulation. A new pressure-buildup test was performed to assess the effectiveness of the fracture stimulation, and detailed analyses indicated that the small reservoir size might have been the cause of the rapid pressure decline.
The fracturing design was based on pressure data from the initial drillstem test (DST) at 388.9 kg/cm2 (5,531 psi). A post-fracture pressure-buildup test revealed that reservoir pressure had declined to 233.2 kg/cm2 (3,317 psi) after only producing 6901 m3 (43,406 bbl). The pressure-buildup analysis detected a fourth boundary that was not mapped during the original three-dimensional (3D) seismic survey. This fault reduced the well drainage area by a factor of four and was the cause of the rapid pressure decline during production. A recent seismic survey refined the geological map of the entire reservoir and confirmed the presence of this fault.
Petrophysical analysis of sand C showed higher-quality rock than sand B; however, the resistivity decreased with increasing sand C depth, suggesting the presence of water. Lithology analysis confirmed that the decrease in resistivity was resulted from higher clay content and clay-bound water. Offset wells also confirmed that the oil-water contact (OWC) was approximately 70 m (229.7 ft) below the bottom of this well. Well productivity could have been significantly higher if the entire sand B pay was initially completed. To compensate for low-formation pressure, a gas-lift optimization procedure was performed to lift the fluid to surface with an initial production of 2.14 m3/h (323 STB/D). After two years, the reservoir pressure in this bounded section declined to 169 kg/cm2 (2,404 psi).
This paper discusses an integrated approach to increase oil production from a well penetrating a geologically challenging environment. Integration of geology, petrophysics, seismic, production modeling, and gas lift with proper data acquisition helped prevent abandonment of this well, leaving behind potential reserves. This paper also discusses a case study in which a false-formation damage diagnosis could have led to reservoir mismanagement.
Wettability alteration has been investigated by research groups over the past two decades as a possible answer to the problem of condensate blocking in order to mitigate its effect on productivity loss, however, very limited field applications have been attempted with one case of success and two cases of failure. A volume of experimental and simulation studies have been published, but these papers rarely identify the factors that can contribute towards the success or failure of such a stimulation method. The absence of an actual economic analysis of this method in the literature is also evident. In this study, we build upon the experience of the research team in this area in order to produce a comparative study to be able to identify the conditions under which wettability alteration can be recommended as a suitable approach to address condensate blocking.