Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
Effective Fracturing Stimulation in the BRN Field in Algeria Using a Residue Free Gelled Fluid System
Forno, Luca Dal (eni Algeria) | Latronico, Roberto (eni Algeria) | Mohammed, Omar (Halliburton) | Kateb, Mahmoud (Halliburton) | Rispler, Keith (Halliburton) | Ainouche, Dalil (Halliburton) | Squires, Scott (Halliburton) | Petteruti, Ernesto (eni Algeria) | Fragola, Daniele (eni Algeria) | Allal, Mohammed A. (Sonatrach) | Hachelaf, Houari (Sonatrach) | Albani, Danilo (eni Algeria) | Hamdane, Toufik (Sonatrach) | Carpineta, Gabriele (eni S.p.A)
Abstract Hydraulic fracturing for well performance optimization has been implemented for many years in BRN field in north-eastern part of Algeria, operated by Groupement Sonatrach-Agip (a JV between ENI and Sonatrach). Because of unfavorable petro-physical properties of the reservoir, some challenges have been encountered in avoiding any additional damage to the fracture faces and to facilitate the post-job treating fluids flowback. Effective fracturing treatment designs should consider preventive actions for possible fracture conductivity impairment, such as damage attributed to stress, proppant embedment, and damage caused by fracturing fluid residues. Correct proppant selection can minimize effects from stress and embedment, while a suitable fluid system can minimize conductivity impairment from gelling agent solid residue. Traditional guar-based fluid systems, which are often a preferred choice in the industry for fracturing operations, can have damaging effects on fracture conductivity attributed to inherent insoluble residue that can plug proppant pack pore spaces. Implementing a less damaging fluid system can not only maximize retained conductivity, but furthermore provide longer effective fracture half-lengths which may result in more efficient treatment fluid recovery. Therefore, to overcome such issues, a new fracturing fluid has been developed, leaving little or no residue after breaking. Moreover, this fluid system can be tailored to a wide variety of bottom-hole conditions and has comparable properties to guar-borate fluids with respect to proppant transport capacity and rheological characteristics (e.g. viscosity building and breaking behaviors). This paper presents the first successful implementation of this novel fluid system in the BRN field in Algeria for improving the water injection performance of a well characterized by a tight sandstone reservoir. Field data collected after performing the propped fracturing treatment confirm the effectiveness of the fracturing fluid design. Specifically, the following topics will be extensively described within this paper: Characteristics of the BRN field and history of conventional guar-base fluid systems used previously within this field; Specifics of the near residue free fluid system (cross-linker types, pH requirements, etc.); Design considerations for the implementation in the BRN field of this novel fracturing fluid; Results of post fracturing water injection performances.
- Geology > Geological Subdiscipline > Geomechanics (0.66)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.54)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
Abstract For a successful hydraulic fracturing operation, two of the most important properties required from fracturing fluids are transport proppant into the fractured zone and minimum damage to formation and proppant pack conductivity. As the fluid is pumped downhole, it experiences thermal and shear thinning. Shear recovery and thermal stability are critical in terms of successful fracture creation and proppant placement. These fluid properties can be controlled by proper selection of crosslinker and linkable groups. Thermal stability of fluid at high temperatures can be increased by proper selection of gel stabilizers and it also reduces the amount of gelling agent to be used. Conventional gel stabilizer contains sulfur which could contribute to H2S gas when consumed by sulfate reducing bacteria. H2S gas is not only corrosive in nature but also harmful to health and thus, although it performs well, several operators seek sulfur-free stabilizers that can perform equivalent to sulfur-based compounds. This paper describes a sulfur-free gel stabilizer developed for enhancing the stability of fracturing fluid, allowing a lower concentration of gelling agent. This gel stabilizer is sulfur-free, nonhazardous, and biodegradable. It also provides better stability for fluids compared to conventional sulfur containing gel stabilizers. Further showcased is the improvement in stability of crosslinked fracturing fluid using the sulfur-free stabilizer under high temperature (HT) conditions of 280 to 320°F. Rheological tests performed using a Chandler high-pressure/high-temperature (HP/HT) viscometer with and without stabilizer are discussed. Results shows a significant change in terms of fluid stability in the presence of this new stabilizer as it provides better stability compared to conventional sulfur containing stabilizer. Also, shear sensitivity tests performed under multiple high shear rate cycles between 100-935-1700 s showed excellent shear recovery after every high shear cycle by completely rehealing in less than 30 seconds.
- Research Report > New Finding (0.48)
- Research Report > Experimental Study (0.48)
Fracturing Fluid Rationalization: First Dual-Viscosity Fracturing Fluid Application in the Middle East
Mira, Ali (Sahara Oil and Gas) | Samir, Mohamed (Sahara Oil and Gas) | Naby, Mohamed Abdel (Sahara Oil and Gas) | Mohamed, Nelly (Schlumberger) | Rojas, Jose (Schlumberger) | Kamar, Ahmed (Schlumberger) | El Sebaee, Mohamed (Schlumberger)
Abstract Dual-viscosity fluid is a fracturing fluid that has been recently introduced to cover a wide range of fracturing applications varying, from a non-delayed to delayed fluid system for treatments in low to moderate to high temperatures, respectively. Reducing the impact of the pressure effect of traditional borate cross-linked systems, the system crosslinker is compact and delivers a relatively high concentration of crosslinker per unit volume; it is also compatible with current metering pumps, covering a range of treatment rates compared to the current fluid system, and this can simplify logistics on location. The North Bahariya oil fields are onshore fields located in the Western Desert of Egypt and operated by Sahara Oil and Gas Company (SOG). The fields contain proven oil reserves in two sandstone packages at relatively shallow drilling depths (6,500 ft. subsea) in the Abu Roash "G" member (A/R G) of Cenomanian (Cretaceous) age. These sandstones comprise the main reservoirs in the field. During the last 4 years, the introduction of various techniques has led to a fourfold increase in the production from these fields. This success story is mainly the result of using the new hydraulic fracturing methods such as channel fracturing technique and continuous improvement of the fracturing treatments. SOG has been at the forefront in applying novel technologies to optimize the fracturing fluid treatment by using the dual-viscosity fracturing fluid to improve the wells potential. This technology has been implemented in Abrar field. As seen in case studies, very positive results have been seen in both zones of the A/R G formation in terms of improvement in the well performance. Experiences in Abrar field illustrate how to optimize the production rate in a marginal field by optimizing the hydraulic fracturing treatment fluid and how to build on this success for subsequent fields while pushing the innovation envelope further.
- Africa > Middle East > Egypt > Western Desert > Greater Western Dester Basin > Abu Gharadig Basin > North Bahariya Concession > Abrar Field > Abu Roash Formation (0.99)
- Africa > Middle East > Egypt > Western Desert > Greater Western Dester Basin > Abu Gharadig Basin > Abu Roash Formation (0.99)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.94)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.94)
Supramolecular Viscoelastic Surfactant Fluid for Hydraulic Fracturing
Yang, Jiang (RIPED-Langfang, PetroChina) | Lu, Yongjun (RIPED-Langfang, PetroChina) | Zhou, Caineng (RIPED-Langfang, PetroChina) | Cui, Weixiang (RIPED-Langfang, PetroChina) | Guan, Baoshan (RIPED-Langfang, PetroChina) | Qiu, Xiaohui (RIPED-Langfang, PetroChina) | Liu, Ping (RIPED-Langfang, PetroChina) | Ming, Hua (RIPED-Langfang, PetroChina) | Qin, Wenlong (Xi'an Petroleum University) | Ji, Sixue (Xi'an Petroleum University)
Abstract This paper studied a new fracturing fluid based on a supramolecular complex of associative polymer and vsicoelastic surfactant. The crosslink complex gel was based on weak physical attractive forces such as van der waals, hydrogen bonding and electrostatic interaction between associative polymer and wormlike micelle of viscoelastic surfactant. The fluid contained surfactant ten times less than that of conventional viscoelastic surfactant fracturing fluid. The combination of viscoelastic surfactant and associative polymer synergistically enhances the viscosity ten times more than that of the individually components alone. The fluid system was optimized by experimental design. The microstructure of wormlike micelle was verified by cryo-transmission electron microscopy. The fluid is shearing-stable at high temperature for 1 hour. The dynamic rheological properties of the new VES fluid showed high viscoelasticity, in which elastic moduli is higher than loss moduli at angular frequency 0.1 rad/s. The proppant transport test in a large-scale fracture simulator showed good proppant suspension ability. The fluid has 50% lower formation damage than that of conventional guar. The fluid was prepared with less additives and formed gel instantly which can be mixed on the fly in the field. The gel can be completely broken with almost no residue. Field application of the new fracturing fluid in a gas field showed the enhancement of gas production over 100%. The fluid has 20% lower friction pressure than that of guar fluid. Hence, the new supramolecular viscoelastic surfactant gel is an effective fracturing fluid with less formation damage.
- Africa (0.47)
- North America > United States (0.29)
- Asia > China (0.29)
- Asia > China > Inner Mongolia > Ordos Basin > Sulige Field > Ordos Formation (0.98)
- Asia > China > Inner Mongolia > Ordos Basin > Sulige Field > 8th section of Shihezi Formation (0.98)
- Asia > China > Inner Mongolia > Ordos Basin > Sulige Field > 1st section of Shanxi Formation (0.98)
- North America > United States > Louisiana > China Field (0.91)
Abstract Tight gas reservoir development has long been affected by 1) complex flow profiles and 2) the impact of very low permeability on reservoir productivity. Where well tests (WT) buildup is very short, interpretation becomes difficult and results often are ambiguous. Most WT of tight, dry gas wells are of short duration; thus, such tests typically lead to multiple interpretations and open-ended conclusions. Adding to the complexity, simulation software packages often fail to adequately model flow in fracture networks. A series of well tests were conducted in tight sandstone, dry gas, naturally fractured reservoirs post-induced hydraulic fracturing. The tests were conducted for long durations: 100 hours in most cases, and 1,000 hours in two extended well-test cases. The WT responses from these tests were ambiguous. We have investigated possible direct causes of the ambiguous results, including wellbore, geology, and specific well conditions. However, because the WT response has been found repeatedly in a variety of regions around the world, it may not be related to any of these. After investigating in multiple manners, including the use of simulation software, we argue that the anomalies in the WT response may reflect a step in the scale-dependent properties of the fracture network.
- North America > United States > Texas (1.00)
- North America > Canada (0.94)
- Africa (0.68)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.91)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (28 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (2 more...)
Impact of Wellbore Orientation on Fracture Initiation Pressure in Maximum Tensile Stress Criterion Model for Tight Gas Field in the Sultanate of Oman
Briner, Andreas (PDO) | Florez, Juan Chavez (PDO) | Nadezhdin, Sergey (Schlumberger) | Gurmen, Nihat (Schlumberger) | Alekseenko, Olga (ICT) | Cherny, Sergey (ICT) | Kuranakov, Dmitry (ICT) | Lapin, Vasily (ICT)
Abstract The goal of the present work is to numerically simulate the effects of wellbore orientation on fracture initiation pressure (FIP). These simulations support the study of FIP sensitivity to arbitrary wellbore position and finding the orientations that correspond to the lowest FIP. A 3D numerical model of the fracture initiation from a perforated wellbore in linear elastic rock is used to model FIP. This model is based on the boundary element method (BEM) and maximum tensile stress (MTS) criterion. The data used were from different zones and blocks of a tight gas-bearing sandstone field in the Sultanate of Oman. The amount and quality of available data allowed comprehensive model development. The model is built for the four blocks of the main field, but can be applied to the other blocks and fields. Since the equations and correlations are not empirical and not field-specific, the model is applicable to a wide range of conditions. Some practical applications of the study include selection of the optimum perforated intervals intended for fracturing stimulation in deviated or almost horizontal wellbores where different parts of lateral sections are not exactly aligned with principal stresses. Drilling wells in a particular direction to the principal stresses for the specific reason to reduce the FIP has not been tested to date and is a subject to further discussion.
- Asia > Middle East > Oman > Fahud Salt Basin (0.99)
- Asia > Kazakhstan > Aktobe Oblast > Precaspian Basin > North Block (0.99)
- Well Drilling > Wellbore Design > Wellbore integrity (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Well Completion > Completion Installation and Operations > Perforating (1.00)
- (2 more...)
Future Trends for Tight Oil Exploitation
Zhang, K.. (University of Calgary) | Sebakhy, K.. (University of Calgary) | Wu, K.. (University of Calgary) | Jing, G.. (University of Calgary) | Chen, N.. (University of Calgary) | Chen, Z.. (University of Calgary) | Hong, A.. (University of Stavanger) | Torsæter, O.. (Norwegian University of Science and Technology (NTNU))
Abstract In this paper, production characteristics of tight oil reservoirs are summarized and analyzed, the investigated reservoirs include Cardium sandstone reservoir and Pekisko limestone reservoir. The phenomenon that gas and oil or water and oil are co-produced at an early stage of exploitation has been observed. In addition, water cut of many tight oil producers remains constant or undergoes reduction as production proceeds within first 36 months. Since an oil rate drops quite a lot in the first year's production of tight oil reservoirs, reservoir simulations are run to investigate an effect of different parameters on tight oil production. Randomized experiments are created with geological and engineering parameters as uncertain factors and an oil rate as the response factor. The method of analysis of variance (ANOVA) is used to analyze the difference between group means and to determine statistical significance. Reservoir properties such as permeability, pressure, wettability, oil API, and oil saturation and engineering parameters including a fracture stage and well operations have tremendous effects on oil production. Oil recovery factor increment in tight oil reservoirs highly depends on enlarging a contact area, improving oil relative permeability, reducing oil viscosity and altering wettability. Future research and development trends in tight oil exploitation are highlighted. As primary recovery is quite low in tight oil reservoirs, the multistage fracturing technology is a necessity and it must be conducted based on a deep understanding of petrophysical and geomechanical properties. Water alternating gas (WAG) seems the best fit for tight oil exploitation. The way to improve WAG performance, including CO2 foam stabilized with surfactant or nanoparticles, low salinity water or nanofluids alternating CO2, will earn more and more attention in the future of tight oil development.
- Asia (1.00)
- North America > Canada (0.70)
- Europe (0.69)
- (3 more...)
- Geology > Geological Subdiscipline > Geomechanics (0.88)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.58)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > South Dakota > Williston Basin > Buffalo Field > Red River Formation (0.99)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (32 more...)
- Well Completion > Hydraulic Fracturing > Multistage fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- (4 more...)
Pressure Transient Analysis for Composite Tight Oil Reservoirs after Fracturing
Xu, Jianchun (China University of Petroleum (East China)) | Han, Guangwei (China University of Petroleum (East China)) | Jiang, Ruizhong (China University of Petroleum (East China)) | Deng, Qi (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Zhao, Yulong (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University)
Abstract In this paper, a new mathematical model of multistage fractured horizontal well (MsFHW) considering stimulated reservoir volume (SRV) was proposed for tight oil reservoir considering different regions and formation properties. In this model, two regions with different formation parameters were distinguished. Non-steady state flow in matrix was considered which is reasonable for tight oil/gas formations. The SRV is characterized by the inner region. Both inner and outer regions were assumed as dual porosity medium. Then, the solution of multistage fractured horizontal well performance analysis model is obtained by the point source function method and the source function superposition principle. The pressure transient analysis (PTA) for well producing at a constant production rate was obtained and discussed. At last, different flow regimes were divided based on PTA curves. The effects of related parameters such as SRV radius, inner-porosity coefficient, mobility ratio, fracture number, fracture half-length and fracture spacing were analyzed.
- Africa (0.46)
- Asia > China (0.31)
- North America > United States (0.28)
- Geology > Geological Subdiscipline > Geomechanics (0.90)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.63)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- Asia > China > Xinjiang Uyghur Autonomous Region > Junggar Basin (0.99)
- Asia > China > Shanxi > Ordos Basin (0.99)
- (2 more...)
- Well Completion > Hydraulic Fracturing > Multistage fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Abstract Mud loggers are the first (and sadly in some cases the only) people to look at the cuttings. To actually see what the rocks look like, feel like, occasionally even taste. Most people looking at a well will actually look at “wriggly lines” or at best the cuttings descriptions from the loggers or geologist, two or three lines of abbreviations “claystone, light grey to grey, soft to firm, occasionally hard, slightly calcareous, trace fine sand”. We have all read them, many of us have written them. These descriptions are incredibly useful and valuable, they are often all we have to understand the actual rocks and geology, especially with older wells. But in a world where we now enter the description and draw the logs with a computer, this information still comes from the subjective view of the logging geologist peering through a microscope In recent years, several tools have been developed to analyze drill cuttings from oil and gas wells. The most commonly used tools include X-ray fluorescence (XRF), X-ray diffraction (XRD), scanning electron microscopy (SEM) combined with energy dispersive X-ray spectroscopy (EDX), bulk density, and pyrolysis. Although each of these tools can be used to develop a limited determination of the in-situ rock character, the combination of three of these tools (XRF, SEM/EDX, and pyrolysis) can provide a more comprehensive picture of formation properties. The combination of XRF analysis with the SEM/EDX analysis is the key to the cuttings workflow. The exact location within the borehole can be determined and a robust mineralogy developed that is independent of normative mineralogy (typical XRF) or operator-interpretive mineralogy (XRD). Additional outputs include relative brittleness index, bulk density, lithology, fractional and textural relationships, total organic carbon (TOC) proxy, and a new porosity index. Trace and major elemental ratios are also available for precise stratigraphic placement. The addition of cuttings pyrolysis enables hydrocarbon typing, producible hydrocarbons, TOC, and total inorganic carbon (TIC) within each sample to be established. Chemical Lithostratigraphy uses whole rock inorganic geochemical (elemental) data, to give information on: Extrabasinal source area dominance and origin (volcanic, metamorphics, igneous, sedimentary), Extrabasinal component weathering or diagenesis (cementation) Intrabasinal components (Palaeo-environment and insitu origin of sediments) Chemical Lithostratigraphy analysis of cuttings can be done either in the laboratory or at the rig site using technology advanced Surface Logging Services (SLS) that includes both XRF and XRD equipment, in additions to SEM and Pyrolysis. Where an appropriate protocols uses for cuttings fraction that are most depth representative With the growing interest in hydraulically fracturing reservoirs both in main land USA and now globally, there has been a growing need to better characterize the reservoir to maximize hydrocarbon recovery while also reducing the overall cost in the recovery of the hydrocarbon. With current fracc-ing regimes relying on a large number of stages to ensure maximum recovery, which in many cases leads to upwards of 30% of these stages being unproductive. This reduces the overall profitability of the well even with maximum hydrocarbon recovery. With the ongoing development of automated mineralogy tools, such as the RoqSCAN, there is now the ability to characterize a reservoir at the well-site in real-time and also rapidly in a laboratory. In this paper we will review the current development of these mobile and ruggedized instruments using a real life project for Eagleridge Energy LLC, on their Burgess lateral well. The paper will show the application of automated mineralogical analysis of cuttings samples pre-drilling in defining stratigratic zones via mineralogy/elemental data. And then explore the application of the same data to assist, and in this case lead, the decision making process during directional drilling of the lateral well. The paper will also look at the use of the technology in defining tactical fracc-ing zone based on rock properties (e.g. ductility) determined from the mineralogical, elemental and textural data. This paper will show that through the use of automated mineralogical instruments, companies can pro-actively steer wells by identifying mineral changes within lateral borehole, indicating a deviation from the target zone. Additionally, this type of technology can be used to reactively steer by its ability to rapidly identification subsurface changes, such as unknown (undetected) faults. Finally the paper will show that through the better characterization of this reservoir companies can reduce the risk associated with the drilling of expensive lateral wells.
- North America > United States > Texas (1.00)
- Asia > Middle East > Saudi Arabia (1.00)
- Africa > Middle East > Egypt (1.00)
- (4 more...)
- Geology > Geological Subdiscipline > Mineralogy (1.00)
- Geology > Geological Subdiscipline > Stratigraphy > Lithostratigraphy (0.44)
- Geology > Geological Subdiscipline > Stratigraphy > Chemostratigraphy (0.40)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock (0.35)
- North America > United States > Texas > Fort Worth Basin > Chappel Formation (0.94)
- North America > United States > Texas > Fort Worth Basin > Barnett Field > Barnett Shale Formation (0.94)
- North America > United States > Kansas > Chester Formation (0.93)
- (2 more...)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Drilling > Drilling Measurement, Data Acquisition and Automation > Mud logging / surface measurements (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- (2 more...)
Abstract Proppants are required in hydraulic fracturing operations in the oil and gas industry. They consist of solid particles with specific strengths and are used to keep the rock fractures open in order to increase well production. They can be naturally occurring sand grains or artificial ceramic materials. Studying the acid resistance of proppants is important. Acids are needed to remove the scale and clays that affect the fracture conductivity. This study investigated the different factors affecting the interactions between mud acid and sand proppants. Several experiments were conducted using the aging cell with mud acid (3 wt% HF, 12 wt% HCl) up to 300°F. The effects of temperature, soaking time, and static and dynamic conditions were examined. The supernatant of solubility tests was analyzed to measure total silicon concentrations using ICP-ES. The proppant was sieved before and after the experiments. Following that, the residual solids were dried and analyzed using a scanning electron microscope (SEM). The results showed that sand proppant is soluble in regular mud acid, nearly 10 wt% dissolved in some cases. The amount of proppant dissolved increased with temperature, soaking time, concentration, and dynamic conditions. The fines generated and the changes in grain size distribution are detrimental to the proppant conductivity. This work will help to achieve a better acid treatment design when sand proppant is used.