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Abstract This paper presents an extension of Yang's Y-function method (a function of oil fractional flow) aiming to improve performance analysis of a mature waterflood or waterdrive reservoir for any oil-water viscosity ratio condition. The new approach is based on an appropriate mathematical expression that substitutes the traditional semilog linear relationship between the oil-water relative permeability ratio and water saturation. The production decline analytical method to diagnose waterflood performance as proposed by Yang (2009a and 2009b) and derived from the solution of the one-dimensional (1D) frontal advance Buckley-Leverett (BL) equation, applies to reservoirs with water breakthrough starting from semilog linear section of the kro/krw vs water saturation plot and with moderate oil-water viscosity ratios. To solve this flow equation, the fractional flow curve, which is function of oil and water viscosity and also oil and water relative permeability ratio, must be known. The traditional semilog linear relationship of oil-water relative permeability ratio for intermediate water saturation range has been consistently used to solve fractional flow and then the BL equation. Because the water saturation at breakthrough (Swbt) moves to the boundaries of the water saturation range at both very unfavorable and favorable oil-water viscosity ratio, the use of the traditional semilog linear trend to both extreme conditions of oil-water viscosity ratio could lead to unrealistic oil prediction during the productive period of waterflooding or waterdrive. Therefore, a representative oil-water relative permeability ratio and water saturation approach of the reservoir rock is necessary to obtain reliable predictions at and after water breakthrough. This paper presents the use of the resulting expression of solving the derivative (with respect to water saturation) of the quotient between individual power-law expressions of relative permeability for both oil and water phases, specifically from Corey's correlations of relative permeability curves. The resulting term named B' that substitutes the constant parameter B in the Y-function is presented in this work. Theoretical and field data examples are also presented to illustrate this approach. Results show that the new approach (the comprehensive Y-function, cY) derives a solution with a slope m that can be different than -1 for a normal displacement efficiency from the log-log plot of Y vs. tD, therefore m value from real field data will reflect the displacement efficiency imposed by reservoir characteristics and/or operational conditions. This new approach also improves reliability when calculating the volumetric sweep efficiency (areal sweep efficiency times vertical sweep efficiency) and predicting both water and oil cut of mature waterflood or waterdrive reservoirs. It also expands the Yang's model application by improving its performance during both very unfavorable and favorable oil-water viscosity ratio, particularly at and after water breakthrough.
- Overview > Innovation (0.75)
- Research Report (0.54)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
Abstract Water is the most commonly used injection fluid for flooding/energizing oil reservoirs. Despite oil price fluctuations, water use has continued because of its wide availability, relatively low cost, and ease of handling. Decades of research and field application experiences have yielded a sound theoretical approach and practical knowledge of the subject. Nevertheless, water injection deployment and operations can still benefit from optimization. This paper discusses the state-of-the-art use of numerical optimizers based on smart algorithms and stochastic machines that couple subsurface, surface, and economic models. During planning and operations of waterflooding projects, many decisions are made, such as the number, location, and drilling sequence of new injector and producer wells, total and per well injection rates, well conversion, and fluid withdrawal rates. In addition, each decision variable has multiple options, which combined can generate hundreds or thousands of scenarios, raising the key question of how the optimum scenario can be determined in a timely manner. Furthermore, the optimum scenario selection process should consider uncertainty (e.g., reservoir properties and oil prices) as well as operational constrains. Based on previous experience, a general workflow was developed and fine-tuned to help identify optimum scenarios. The workflow begins by defining the scenario matrix using available validated history-match models. Models are coupled with an automatic optimizer/stochastic machine. The study cases considered reservoirs with heavy-to-medium oil, injection by pattern and flank, large variations in original oil in place (OOIP), and number of wells for waterflooding implementation and reactivation planning. Optimization runs typically require hundreds of iterations to approach the maximum or minimum objective business function. Each iteration corresponds to a scenario. To identify the optimal scenario quickly, various strategies were tested: parallel computing and new methodologies of sequential optimization with reduced number of decision variables, initial exploratory runs with a shortened economic horizon time, and stochastic analysis of selected scenarios of the optimization run. All of these strategies proved successful, depending on the specific situation. The workflow application in three case studies yielded approximately 30% cumulative production and net present value (NPV) increments, with less economic risk than the traditional deterministic simulation approach and reduced water cut up to 40%; compared to base scenarios, Np and NPV increases higher than 200% were obtained. Furthermore, the workflow application generated a large number of scenarios that provided flexibility to modify operations during unexpected events. Optimizers/stochastic machines were determined to be a valid means to quantitatively estimate the economy and risks and are a fundamental tool for managing waterflooding projects, resulting in better scenarios than the traditional deterministic approach. The approach is also applicable to all types of enhanced oil recovery (EOR) projects.
- South America (1.00)
- North America > United States > Texas (0.28)
- Research Report (0.66)
- Overview (0.66)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.46)
- Geology > Sedimentary Geology > Depositional Environment (0.46)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.50)
Field Treatment of an Injector Well in a Sandstone Formation Using a Low Corrosive Environmentally Friendly Fluid that Does Not Require Flow-Back
Nuñez, W.. (Oxy Colombia) | Bautista, O.. (Oxy Colombia) | Cepeda, F. A. (Oxy Colombia) | Kleber, M. A. (Oxy Colombia) | Dos Santos, A. A. (AkzoNobel) | Oliveira, E.. (AkzoNobel) | Rodriguez, O.. (AkzoNobel)
Abstract Throughout a waterflood project, injector wells can experience scale build up mostly related to formation-water incompatibilities; as a consequence, injectivity index (II) decreases and vertical conformance can suffer leading to poor sweep efficiency. Stimulation treatments are required to reestablish well injectivity; usually Hydrochloric acid and Regular Mud Acid are used in sandstone reservoirs. Such treatments involve a number of difficulties such as handling highly corrosive fluids, risk of clay instability, secondary reactions and time-consuming flowback of spent treatment in low pressure reservoirs. Recently, a novel chemical was identified to effectively dissolve scale obstructions in injector wells while avoiding the operational constrains found in traditional acidizing jobs, including the need of flowback. Fluids containing the environmentally friendly chelating agent Glutamic acid N, N diacetic acid (GLDA), were tested in the laboratory under downhole conditions to evaluate the dissolution of a scale sample from the field composed by Fe2O3 and CaSO4. Additionally, core-flood, compatibility and corrosion tests were carried out to evaluate the interaction with clays, formation and well's metallurgy. Results showed effective dissolution of the scale sample, while being fully compatible with formation clays and fluids which indicated that the treatment could be left downhole and pushed into the formation without causing further formation damage. Furthermore, corrosion tests showed no need of corrosion inhibitor for a low carbon tubular under tested conditions. Field implementation took place in an on-shore injector well completed selectively with injection valves between packers. A two stage treatment was designed; the target of the first phase was cleaning out the injection valve itself and the tubing-casing annular space of this interval, and the second stage aimed the dissolution of scale located in the perforations and deeper into the formation. Step rate tests were performed before and after the treatment to evaluate well injectivity. Low injection treatment rates and soaking allowed enough time for the GLDA to effectively dissolve the scale obstruction along the treated interval; spent treatment was pushed further into formation once regular water injection was reestablished with a 51% increase in its injectivity index. The use of GLDA in the field was considered cost-effective due to the lack of additives, no need for of N2 to kick-off flow-back, nor flow-back fluids neutralization and disposal.
- North America > United States (1.00)
- South America (0.94)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.47)
- Well Completion (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
Abstract The Papagayos formation in the Cuyana Basin, Argentina is one of the most prolific and mature reservoirs in the YPF portfolio. Currently it has a 98% water cut with an estimated recovery factor of 56%. The challenge was to determine if there was untapped oil in the field and subsequently how to economically extract it. To identify the source of the current oil production and potential new oil, well logs on infill wells were analysed. We also constructed a full field dynamic model that was history matched to production rates, RFT’s, gradient surveys and compared to historical water saturations identified on infill wells. To reduce uncertainty and to confirm the mechanism by which oil remained in the subsurface, we cross referenced the results of the simulation model against lab 2D visual cells filled with glass spheres to reproduce any trapped oil seen in the simulation. Well logs saw oil at the top of the reservoir; however it was not known if this oil was mobile. With the parameters history matched, the simulation showed the presence of mobile attic oil underlain by a water saturated zone swept by the aquifer. The simulation also demonstrated that the reservoir has multidarcy permeability; hence water coning would be a major issue to consider. The simulation model enabled an estimation of the aquifer strength and demonstrated that it would have a major impact on any recovery process. Simulations were made to determine if the aquifer could be either used to assist any new recovery process or otherwise if it could be subdued. Multiple EOR options were considered to exploit this remaining attic oil, however the most economic option was to augment the aquifer by injecting water on the flanks. Lab results corroborated the simulation and showed that attic oil could be a result of both coning and the structure of the reservoir. Also it was seen that increasing water injection rate into the 2D visual cells (augmenting the aquifer at high water cuts) lead to an increase in oil recovery. Despite a strong aquifer and both high water cuts and recovery factor, it was possible to identify and develop economic oil by applying an integrated modeling methodology. The model demonstrated that augmenting the aquifer is easier than fighting it by applying an EOR approach that requires massive injection to overpower the aquifer. Linking simulated reservoir response to 2D visual cell displacements demonstrated the effectiveness of flank water injection in increasing oil recovered.
- Geophysics > Borehole Geophysics (0.70)
- Geophysics > Seismic Surveying (0.69)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.76)
- South America > Argentina > Mendoza > Cuyo Basin > Vizcacheras Field (0.99)
- South America > Argentina > Cuyana Basin (0.99)
- South America > Argentina > Mendoza > Cuyana Basin > Barrancas Field (0.93)
- Reservoir Description and Dynamics > Reservoir Simulation > History matching (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Conformance improvement (1.00)
Abstract In Shale plays, EUR relies almost exclusively on "primary" production with practically no account for Enhanced Oil Recovery (EOR) practices. However, many remarkable facts are sometimes considered as "anecdotic" or pointed out as outliers, rather than including them as part of a coherent explicative model. Both, included in the literature and commented by the operators, we have repeatedly found many cases reporting such "anomalous" facts such as: (i) Low liquid recoveries during flow back periods, (ii) Rapid salinization of flow back water, (iii) Higher productivities correlating with lower percent of flow back recoveries, (iv) Early oil production right after flowback starts, (v) Shales described as "thirsty" or "dehydrated" (meaning lower water saturation than expected due to its pore geometry) and (vi) the evidence of huge capillary pressures, developed and supported by well documented overpressures. After accepting these "anomalies" as an intimate part of the behavior of these non-conventional scenarios, we get many major consequences in the way we could develop and exploit them. Thus, we propose a new methodology that consists on a novel operative sequence to enhance oil production in multi stage frac Shale Oil scenarios. The main mechanism involves countercurrent water imbibition processes, and consists of a cyclic scheme of (i) water injection, (ii) soaking and (iii) production periods that could be repeated until capillary effects fade out. This methodology, if proven successful, means a complete shift of the current exploitation practices, probably leading to a new paradigm in the way these unconventional resources could be developed and produced. This proposal, if proved successful, should have a paramount impact in the appraisal and economics of these types of resources development, not only improving recoveries with low cost operations to transform resources into reserves, but also leveraging operational issues such as paraffin deposition, pressure maintenance, potential acid treatments, etc. The approach involves a de risking process in three stages (i) conceptual, (ii) theoretical and (iii) experimental (lab and field tests). This paper describes the status of development of the analysis and the findings so far, which show encouraging results to continue imrproving the technique and perform additional field testing.
- North America > United States > Texas (1.00)
- South America (0.70)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (0.88)
- South America > Argentina > Patagonia > Neuquén > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (29 more...)
Abstract Polymer flooding has now become a relatively well accepted method to increase production and recovery in heavy oil fields. Numerous pilots have taken place these last few years and field expansions are currently ongoing in several fields such as Pelican Lake (Canada), Marmul (Oman), Bohai Bay (China), Diadema (Argentina) and Patos Marinza (Albania). As a result of these recent developments, field data has now become available in large quantity and can be used to provide guidance on the impact of various parameters on expected flood performances. For instance, a comparison of primary, secondary and tertiary polymer flood performances based on the analysis of several polymer flood patterns in Pelican Lake was presented in 2016 (Delamaide, 2016). The present paper proposes to go further and to investigate the impact of parameters such as pore volume injected, well length, well spacing or Voidage Replacement Ratio (VRR) on polymer flood performances, based on data from fields in Canada and other parts of the world. The performances of over 70 patterns belonging to several heavy oil polymer floods were analyzed and the impact of VRR, well spacing, well length and other parameters on recovery was evaluated. The calculations were performed using actual reservoir and production data whenever possible and published data in other cases. Despite a large scatter in the data due to the wide range of reservoir conditions investigated, it is possible to distinguish interesting trends. For instance, higher VRR corresponds to lower recovery and recovery is fairly well correlated to injected pore volumes. This paper will provide guidance to engineers designing polymer floods in heavy oil fields, allowing to adjust some of the design parameters to improve field response. In addition, the results can also be used to benchmark reservoir simulation results which can often be too optimistic or to compare performances of pilot projects in other fields.
- South America (1.00)
- North America > Canada > Alberta (1.00)
- Europe (1.00)
- (2 more...)
- 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 > Colombia > Santander Department > Middle Magdalena Basin > Yariguí-Cantagallo Field (0.99)
- (16 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Integrated Modeling of Formation Damage and Multiple Induced Hydraulic Fractures During Produced Water Reinjection
Fischer, K.. (Schlumberger) | Ferreira, F. C. (Schlumberger) | Holzberg, B. B. (Schlumberger) | Pastor, J. S. (Schlumberger) | Reinli, L.. (Statoil) | Furuie, R.. (Statoil) | Vasconcelos, D. M. (Statoil) | Dutra, T. A. (Statoil)
Abstract During produced water reinjection into an oilfield, the formation near the wellbore is progressively damaged due to total suspended solids (TSS) and oil particles in the injected water (OIW). This typically increases the bottom-hole injection pressure over time. Furthermore, if the water is injected in the oil zone, the initial bottom-hole injection pressure may already be high from the start due to water mobility constraint and oil viscosity. This study aims to model the generation of hydraulic fractures induced under different conditions, their geometrical characteristics and corresponding development over time. Such information is key to reservoir simulation for the secondary oil recovery and to reservoir integrity assessment. Four disciplines are integrated into the proposed workflow: reservoir flow simulation, formation damage modeling, reservoir geomechanics, and the simulation of hydraulic fracturing. First, a sector model around an injector well is extracted from the full-field reservoir simulation of the case-study reservoir. In the reservoir flow simulation, a formation damage model is implemented, calibrated from injection rate, bottom-hole pressure, TSS and OIW actual data. At specified time steps, the flow simulator passes pore pressure profiles of the sector model to the geomechanical simulator, which computes the corresponding changes in stress and deformation. The updated in-situ stress field, in combination with the petrophysical model applied for the flow simulation, is provided to the hydraulic fracturing simulator, which tests for the development of the hydraulic fracture and computes its geometry. The resulting hydraulic fracture is mapped back into the reservoir flow model to account for the local increase of permeability of the cells hosting the fracture. The workflow then enters into a loop starting again with the flow simulation, and the further development of the fracture under changing conditions is tested and modeled. The proposed workflow was successfully applied to an injection well in an offshore field. Four scenarios considered different initial formation saturation, injected fluid viscosity and the conversion of a producing well into an injector. Multiple fractures with different characteristics, fully contained inside the reservoir, were predicted for each scenario and gave insights into the hydraulic fracture development during produced water reinjection. The proposed method and workflow have the potential to significantly improve the reservoir simulation of the water injection process for secondary recovery or pressure maintenance by providing insights into how induced fracture geometries will influence the injection pressure and reservoir sweep efficiency. It also may provide valuable information to assess the integrity of reservoir cap rock during produced water reinjection.
- Europe (1.00)
- North America > United States > Texas (0.28)
- North America > United States > California (0.28)
- Research Report > New Finding (0.93)
- Research Report > Experimental Study (0.93)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.69)
- Europe > Norway > North Sea > Central North Sea > Central Graben > Block 2/8 > Valhall Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > Block 2/8 > Valhall Field > Hod Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > Block 2/11 > Valhall Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > Block 2/11 > Valhall Field > Hod Formation (0.99)
Abstract The current low oil price scenario makes it increasingly critical to build robust business cases, to model uncertainty and to identify the most efficient and economically viable scenarios for any field development or redevelopment strategy. The purpose of this paper is to present a multi-scale reservoir modelling approach to assess economic viability for the development of an EOR project in an adverse oil price scenario. We present an on-going polymer injection project in a brown oil field in the Western Flank of the Golfo San Jorge Basin in southern Argentina as case study for this methodology. Productive interval consists of a 1000 meters-thick low net-to-gross fluvial succession, in the Cretaceous Bajo Barreal Formation. The field produces a ~100 cp oil with very low recovery factor and a watercut of 94%, after 25 years of waterflood. The need for high resolution models is validated by a cell size sensitivity analysis on polymer injection simulations. We verified that almost 50% error on oil incremental forecasts by polymer injection is obtained if 50 × 50 m cells were used. Therefore, combining purpose-built dynamic models in different scales and economic evaluation we support the on-going execution of the EOR pilot project. Several static/dynamic models are built at different scales (from 10 km to 100 m) to capture depositional trends and model stratigraphic and sedimentary heterogeneities. We evaluate different physical aspects of the polymer injection process with specifically designed numerical simulations at appropriate resolution. We think that detailed modelling and data acquisition are highly profitable decisions even in current challenging economic scenario, aiming at reducing uncertainty and strengthening business cases. Indeed, laboratory and field measurements, identification of critical variables, and high resolution modelling proved to reduce forecast uncertainty and strengthen business case economic indicators.
- North America > United States (1.00)
- South America > Argentina > Patagonia (0.55)
- Geology > Rock Type > Sedimentary Rock (0.68)
- Geology > Geological Subdiscipline > Stratigraphy (0.54)
- Geology > Sedimentary Geology > Depositional Environment > Continental Environment > Fluvial Environment (0.49)
- South America > Argentina > Santa Cruz > Golfo San Jorge Basin > Los Perales Field (0.99)
- South America > Argentina > Patagonia > Golfo San Jorge Basin (0.99)
- Oceania > Papua New Guinea > Papuan Peninsula > Central Province > National Capital District > Petroleum Retention License 15 > P’nyang Field (0.97)
- (11 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
Successful Field Application of a New Polymer Flooding Technique Suitable for Mature Oilfields Against Low-oil-Price Background – A Case Study from East China
Wu, X.. (The Research Institute of Petroleum Exploration and Development) | Wu, Y.. (The Research Institute of Petroleum Exploration and Development) | Xiong, C.. (The Research Institute of Petroleum Exploration and Development) | Xu, H.. (The Research Institute of Petroleum Exploration and Development) | Jia, X.. (The Research Institute of Petroleum Exploration and Development) | Shao, L.. (The Research Institute of Petroleum Exploration and Development) | Xiong, Y.. (Dagang Oilfield Company, CNPC) | Zhang, J.. (Dagang Oilfield Company, CNPC) | Wang, A.. (Dagang Oilfield Company, CNPC) | Tian, J.. (Dagang Oilfield Company, CNPC) | Bai, B.. (Missouri University of Science and Technology) | Tian, X.. (Startwell Energy Co. Ltd.)
Abstract DGXJ is a sandstone reservoir with temperature of 113 °C, salinity of 36235mg/L, and calcium and magnesium content of 1152mg/L and 30mg/L respectively. The reservoir is not only vertically multilayered and severe heterogeneous, but also witnesses water flowing channels, irregular and imperfect injecting-production well patterns, high recovery degree (43%) and high water cut (97%). A new particle-type polymer (SMG) slug combined several small linked-polymer-gel (LPG)slugs and pregelled swellable particle (PSP) was applied during 2011-2015 and achieved remarkable technical and economic effect. The application area is composed of 16 injection wells and 22 production wells. Among the 22 wells, 17 get benefit from dual directions or multi directions, which account for 77.3%. Tracer test was applied for accurate identification of planar reservoir heterogeneity, while water injection profile was tested among injection wells to identify inter-layer difference of injectivity. On the basis those tests PI decision technology and Fuzzy Comprehensive Judgment Meth were applied for the identification and classification of inter-well advantageous flowing channels, after which parameters of new polymer flooding combined slug were setup. Tracer testing showed a relatively large difference of water flooding velocity in different directions within the same I/P well pattern with the slowest being 3.00m/d and the fastest being 11.30 m/d. It also showed over 6 times of inter-layer water intaking intensity as inter-layer differences. The total designed volume of slugs was 0.1 PV with the main slug applying the micrometer-level new particle-type polymer SMG of a concentration of 0.2%-0.5%, the pre-set and middle conformance control slugs apply LPG added PSP of concentrations between 0.3%-0.5% and 0.4%-0.5% respectively. During the application, volumetric proportion of conformance slug and SMG slug was increased from designed 1:9 to 4:6 and SMG diameter was adjusted to sub-millimeter level. Test data showed the planar heterogeneity of 15 injection well patterns was relieved with an increase of reservoir sweeping coefficient by 4.3%. By far the reservoir has witnessed production increase for five consecutive years with 51.2% daily oil production rise, 2.5% water cut decrease and 3.12% recovery factor increase. According to economic evaluation, the costs of water flooding and EOR are 41.1 and 28.56 USD per barrel oil produced respectively which heralds the break-even capability of EOR even against a backdrop of oil price plunging to 30 USD/bbl. The case study has proved that good technical and economic results can be achieved through new comprehensive EOR techniques for complex mature fields with late-stage development. Against the background of low oil price, the application of high-efficient EOR techniques is high likely an effective measure to maintain economic and sustainable development. The opinion of the paper may provide some reference for oil companies to make investment decision in low oil price period.
- Asia > China (0.83)
- North America (0.68)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
Abstract This contribution presents the concept of auto-injection with mechanical pump, as an alternative to the initial stage of a waterflooding project without the prior need of building a water treatment and injection pilot plant, aqueducts and injection lines (facilities). This case of study shares the results of this technique applied for first time in the development of a marginal oil field called Cerro Piedra, operated by YPF on the western flank of San Jorge Gulf basin (Patagonia, Argentina). The auto-injector, unlike a multilayer conventional injector, is self-sufficient and simple injection. It produces and injects briny water in the same wellbore; it is not required to invest on facilities to evaluate waterflooding response. Moreover, it forwards the start of injection and consequently quickens the reservoir's response improving project's profitability. The fluid enters to the mechanism's circuit by a crossflow piece, where a hollow mechanical pump, driven by an individual pumping unit and hollow rods (4,600 ft maximum depth), produces up to 700 STB/D of water to the wellhead and pressurizes it up to 2,000 psia. At the surface, a measuring bridge registers flow, pressure and temperature. Finally, the pressurized fluid reenters to the well by the annular tubular-rod and passes through the crossflow piece to the injection zone. The oil field is located 75 miles far away from Las Heras (Santa Cruz, Patagonia Argentina) and 40 miles from the nearest water treatment plant. The San Jorge Gulf basin is filled by a sequence of fluvial sediments which generate thin and low areal extent multilayer reservoirs. Bajo Barreal sedimentary unit is characterized from top to bottom by: briny water levels (3,500-8,000 ppm) to oil productive levels reservoirs. This distribution allows the auto-injector to produce shallow briny water layers and inject it into deeper hydrocarbon reservoirs. The project includes an initial pilot phase to evaluate the waterflooding response, established with five auto-injectors; an intermediate stage of full development, developed by the completion of the water treatment and injection plant and conversion of eight selective injectors; and a final conversion phase, where the auto-injectors are reconverted to traditional injectors. This auto-injection strategy allows us to evaluate the waterflooding response in a marginal virgin zone, without needing to build facilities for water treatment. Therefore it gives a sustainable water management of the field. This alternative approach improves at least 2% of original project's profitability, which was planned with the construction of an injection pilot plant.
- South America > Argentina > Tierra del Fuego Province (0.28)
- South America > Argentina > Santa Cruz Province (0.18)
- Phanerozoic > Cenozoic (1.00)
- Phanerozoic > Mesozoic (0.69)
- Geology > Sedimentary Geology (0.67)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.49)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.31)
- Water & Waste Management > Water Management > Lifecycle > Treatment (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- South America > Argentina > Tierra del Fuego > Magallanes Basin > Tierra del Fuego Basin > Castillo Formation (0.99)
- South America > Argentina > Tierra del Fuego > Magallanes Basin > South-central > Santa Cruz Formation (0.99)
- South America > Argentina > Santa Cruz > Golfo San Jorge Basin > Cerro Piedra Field (0.99)
- (2 more...)
- Well Completion > Completion Installation and Operations (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Health, Safety, Environment & Sustainability > Environment > Water use, produced water discharge and disposal (1.00)