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Abstract Hydrocarbon production from unconsolidated sand reservoirs requires sand control usually consisting of the installation of a screen combined with gravelpacking. Several existing criteria such as Tiffin, Saucier and Coberly can be used for optimal selection of the sand control design. Sand and fines production in oil and gas wells are one of the main challenges and can result in failures of production systems. Especially in unconsolidated sand reservoirs, proper sand control practices are required to prevent reservoir sand production. At Staatsolie sizing of sand control design is based on the Saucier method incorporating the results of reservoir sand particle size distribution of side wall core samples. A Staatsolie-Suriname in-depth research of sand control practices in shallow, low-pressure, heavy-oil unconsolidated sand reservoirs completed with progressive cavity pumps will be presented. The conventional sand control method applied is the installation of formation sand sized wire wrapped screens and gravelpack completion on uniform and non-uniform distributed reservoir sands. Stand alone screen completions have revealed its application in uniform distributed reservoir sands. Sand production and control on depleted and complex reservoirs based on the conventional method has become a major challenge. In Suriname, in three onshore fields approximately 1,500 wells are completed and are in production. With improved sand control practices, failures have been reduced to less than 5 wells per year. The study has demonstrated the challenges and benefits of sand control in these complex unconsolidated Tertiary reservoirs. This has resulted into increased production and economic benefits. Results of lab tests and field cases will be presented and recommendations will be given on the best approach for sand control practices and the most cost effective sand control solutions in unconsolidated shallow sand reservoirs.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Geological Subdiscipline (1.00)
- South America > Suriname > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- South America > Guyana > North Atlantic Ocean > Guyana-Suriname Basin > Tambaredjo Field (0.99)
- South America > Suriname > Suriname-Guyana Basin > Calcutta Field (0.89)
Abstract Bakken well activity and oil production has increased dramatically in recent years, largely because of technological advancements in drilling, completion, and hydraulic fracturing. For one North Dakota operator experiencing downhole calcium carbonate scaling in the pump and production tubing, an innovative inhibition program has been implemented and shown to reduce well scaling frequency. The new scale inhibition program utilizes a solid proppant-based additive from which the scale inhibitor gradually desorbs. With expansion of the development into new fields which exhibit lower scaling risk, the scale inhibition program was then limited to the higher scaling risk fields, reducing cost and simplifying operations. Bakken wells are completed to vertical depths of approximately 10,000 feet with horizontal laterals up to 10,000 feet and produced via multi-zone completions. The operator initially applied high concentrations of liquid scale inhibitor as an additive to fracturing fluid; nevertheless scaling remained a recurring problem. A postmortem of the failed wells was conducted to eliminate failures not directly attributable to calcium carbonate scale and to identify the factors affecting the scale deposition. The postmortem considered the method of hydraulic fracturing, pump intake pressure, scale inhibitor residual, calcium carbonate scaling index, geographic failure concentration, production time to failure, and cumulative water production to failure. Results of this study are detailed in paper SPE 140977 (Cenegy et al. 2011). This paper continues the study and describes the subsequent scale management program initiated. It details the technology implemented and results in effecting downhole failures due primarily to scale. The paper additionally discusses the solid scale inhibitor technology selection, the inhibitor placement process and the steps taken to further optimize and manage costs of the field-wide Bakken scale inhibition program.
- North America > United States > South Dakota (1.00)
- North America > United States > North Dakota (1.00)
- North America > United States > Montana (1.00)
- Water & Waste Management > Water Management > Constituents > Salts/Sulphates/Scales (1.00)
- Materials (1.00)
- Energy > Oil & Gas > Upstream (1.00)
Abstract Flowback of proppant and formation sand often poses serious challenges to operating companies. These solids can cause equipment damage, costly and frequent cleanup treatments, and production decreases. Various mechanisms were found that destabilize the proppant pack, causing the proppant to produce back with the production fluid. Since 2005, curable resin systems for coating proppant on-the-fly during hydraulic fracturing completions and remedial proppant treatments of propped fractures have been applied in Argentina to provide an effective means for proppant flowback control and screenless completions in various basins. Evaluation of these applications has helped determine that optimum concentrations of resin coatings on the proppant in either primary or remedial treatments are necessary to maximize the bonding between proppant grains to lock the grains in place while minimizing any reduction of the proppant pack conductivity. Additives included in the liquid resin systems permit good consolidation properties in the proppant pack, allowing it to effectively handle the shear forces of high production rates and multiphase flow and the effect of stress cycling as the well undergoes producing and being shut in. Field results indicate that on-the-fly resin coating on proppant and remedial treatments effectively stops the proppant from producing back while allowing the well production rates to be maximized as designed. These processes have drastically decreased the number of solids cleanout workovers in the treated wells compared to the offset wells in the same field where resin treatments were not performed. These resin treatments provide a reliable and cost-effective alternative in marginal reservoirs, eliminating the need for sand screens and providing access to other intervals when deemed necessary without wellbore restrictions.
- South America > Argentina (1.00)
- North America > United States > Texas (0.28)
- Geology > Rock Type > Sedimentary Rock (0.68)
- Geology > Structural Geology > Tectonics (0.68)
- Geology > Geological Subdiscipline (0.46)
- South America > Chile > Magallanes > Magallanes Basin > Fell Block > Springhill Formation (0.99)
- South America > Argentina > Tierra del Fuego > Magallanes Basin (0.99)
- South America > Argentina > Tierra del Fuego > Austral Basin (0.99)
- (9 more...)
Abstract Formate brines have been in use since 1995 as non-damaging drill-in and completion fluids for deep HPHT gas condensate field developments. The number of HPHT fields developed using formate brines now totals more than 40, and includes some of the deepest, hottest and highly-pressured reservoirs in the North Sea. The well completions have been both open-hole and cased-hole. An expectation from using formate brines as reservoir drill-in and completion fluids is that they will cause minimal damage to the reservoir and help wells to deliver their full productive potential over the life-time of the field. The validity of this expectation has been tested by examining the long-term hydrocarbon production profiles of eight HPHT gas condensate fields in the North Sea where only formate brines have been used as the well completion fluids. In five of these fields the wells were drilled with oil-based muds and completed by perforating in cased hole with high-density formate brines. In another two of the fields the wells were drilled with formate brines and completed with screens entirely in open hole using the same brines. The last of the eight fields was drilled with formate brine and the wells were then completed with same fluid in either open hole or cased hole. The results of the production analysis provide a unique insight into the impact of a single type of specialist drill-in and completion fluid on the rate of recovery of hydrocarbon reserves from deeply-buried reservoirs in the North Sea.
- North America > United States (1.00)
- Europe > United Kingdom > North Sea > Central North Sea (1.00)
- Europe > Netherlands (1.00)
- Europe > Norway > North Sea > Northern North Sea (0.94)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.68)
- Geology > Sedimentary Geology > Depositional Environment (0.46)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > License P2501 > Block 3/29a > Rhum Field (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 9/9b > Bruce Field > Turonian Limestone Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 9/9b > Bruce Field > Statfjord Sandstone Formation (0.99)
- (54 more...)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > HP/HT reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
Abstract Many studies have been performed to identify chemical additives that will aid shale stability in large volume slick water fracturing treatments. Most of the targeted shale formations have a very low permeability, do not experience conventional leakoff and do not contain high amounts of swelling clays such as smectite, leading to a perception that the shale is not water sensitive. However, recent laboratory evaluations have shown that not all shales are stable in fresh water, destabilizing with fresh water contact and releasing fines which could potentially result in formation damage and reduce net fracture pack conductivity. Previous studies of the ability of inorganic salts, temporary clay stabilizers, and permanent polymeric based clay stabilizers show that some of the common hydraulically fractured shales encounter stability problems when contacting fresh water. The studies have revealed that cationic polymeric permanent clay stabilizers improve the stability of the water sensitive shales. However, polymeric shale stabilizers are not without potential detriments. Polymers can lead to formation damage by blocking pore throats and reducing permeability. Additionally, the use of cationic polymers can limit the use of other chemical compounds used in treating fluids that may not be compatible with the cationic charge. This paper will compare a non-polymeric permanent clay stabilizer to conventional cationic polymers, temporary clay stabilizers, and inorganic salts and demonstrate equivalent and, sometimes, improved performance. Laboratory data from shale stability (roller oven), capillary suction time (CST), and regained permeability (core flow) studies will be presented demonstrating the efficacy of this new compound. Shales selected for the study will include standard Pierre shale and a variety of commonly hydraulically fractured shales from North America. Additionally, chemical compatibility testing will demonstrate the benefits of the new compound over conventional cationic polymeric clay stabilizers.
- North America > Canada > British Columbia (1.00)
- North America > Canada > Alberta (1.00)
- North America > United States > Pennsylvania (0.95)
- (4 more...)
- Phanerozoic > Paleozoic > Devonian (0.93)
- Phanerozoic > Mesozoic (0.69)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- North America > United States > West Virginia > Appalachian Basin > Utica Shale Formation (0.99)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- (29 more...)
Abstract Ecuador is producing oil today from mature fields with increasing water cut, and most of the reservoirs are subhydrostatic with permeability ranging from 10 to 1000 md and significant clay content (mainly kaolinite and glauconite) in the formation matrix. As a consequence of the increasing workover interventions and fluid invasion due to the depleted reservoir conditions, there was need to stimulate the wells to be able to bypass the damage zone. In the past, it was common to lose completion fluid into the reservoir, resulting in a 20% to 50% reduction in production or even in extreme cases killing the well when the completion fluid was incompatible with either reservoir fluids or formation clays. Historically matrix acidizing treatments have been perfomed in an attempt to remove formation damage or to increment production, with limited success. Matrix acidizing treatments are not sufficient to fully remove the damage because of the high clay content, and in many cases, the damage cannot be removed by just treating the critical matrix. Conventional hydraulic fracturing treatments were then tried as a means to bypass the damage. However, some of the wells treated showed positive skin factors following the fracture treatments. The wells in which hydraulic fracturing had proved unsuccessful were studied in more detail to understand the reason why hydraulic fracturing resulted in a positive skin. It was concluded from the formation mineralogy and core flow testing that the fracturing treatments were unsuccessful due to a reduction in the formation permeability due to the mechanical plugging and movement of the kaolinite or disrupted mica in the pore throats. The reduction in the matrix permeability results in skin damage in the faces of the fracture. The fracture-face damage or skin can also be caused by fluid loss from the fracturing fluid through the fracture faces, which creates an additional drop in pressure that may further reduce the productivity of the well. The impact of these effects on the productivity of a treated well depends on the reservoir characteristics and mineralogy, fracture geometry, extent of fluid leakoff into the reservoir, and the viscosity of the fracturing fluid filtrate. The magnitude of these effects and resulting additional pressure drop generally increases with increasing reservoir permeability. To eliminate or mitigate the fracture-face skin effect in water-sensitive formations, a new treatment incorporating a prepad of a viscosified blend of chelants and acid was field tested. By adding this stage into the fracturing treatment design, the retained matrix permeability was increased to +/- 70% of the undamaged matrix permeability, resulting in negligible fracture-face skin. The productivity of fracturing treatments performed using this innovative technique resulted in negative skin factors and production ratios that exceeded expectations in water-sensitive and high clay content reservoirs.
- South America (1.00)
- North America > United States > California (0.46)
- North America > United States > Texas (0.28)
- South America > Peru > Marañón Basin (0.99)
- South America > Colombia > U Formation (0.99)
- South America > Colombia > Putumayo Department > Putumayo Basin (0.99)
- (4 more...)