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Abstract Rock physics models are the quantitative link between the seismic information and reservoir properties. Thus, several authors have been used this link to develop methodologies aiming to integrate seismic derived information and production history matching. Nevertheless, there are significant uncertainties related to petro-elastic parameters definition and its effects on typical history matching results. This paper evaluates this problem through the application of two history matching procedures. The empirical allowed range of petro-elastic parameters regarding fluid and rock behavior, such as temperature, salinity and porosity, mineral and dry rock modulus, respectively, are combined to define different data sets. Each set defines petro-elastic models to be coupled to a numerical reservoir model providing synthetic impedance distributions. These sets of impedance are then used in two different integrated history matching techniques. First, each set is combined with production data defining a global objective function to be minimized and provide a new horizontal permeability distribution resulting in an updated model. Secondly, a constrained inversion procedure is applied to convert impedance into saturation and pressure distributions. These maps indicate the optimization regions and the quantitative seismic information to improve the global objective function minimization accuracy aiming to derive a new permeability distribution. Thus, permeability and bottom-hole pressure from the updated reservoir models are compared to evaluate the several combinations of petro-elastic parameters effects. The major goals of this paper were to quantify the petro-elastic parameters definition effects on history matching procedures, indicating which of them is more sensitive to their variations. Furthermore, it was possible to assess their individual impact in the history matching results and highlight the importance of a careful definition of these parameters and its coherent integration with fluid flow models. This approach also contributes to quantitative integration aspects of oil reservoir development and management.
- Europe (1.00)
- South America > Brazil (0.68)
- North America > United States > Texas (0.28)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Marlim Field > Macae Formation (0.99)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Marlim Field > Lago Feia Formation (0.99)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Garoupa Cluster > Namorado Field (0.99)
- (3 more...)
Abstract 4D seismic has been utilised on several fields for improved reservoir monitoring and management. This paper describes a specific application of 4D seismic data for the analysis of co-mingled injectors. For optimised pressure support and sweep in water-flood projects, an injector can be completed over several different reservoir units. This, however, can introduce uncertainty on the effective injection into each zone. The reservoir quality encountered at each zone can give an indication of expected injectivity, however, this does not take into account dynamic pressure effects in the reservoir and possible completion issues. In certain cases where injection intervals are changed over time, monitoring the changes in the injectivity index during these different modes of operation can be used to infer relative injectivity potentials. PLT results, when available, can also indicate the split of injection into various zones at a given point in time. In addition, if formation pressure data is acquired after production start-up, this can be used to assess the pressure regimes in different zones. 4D seismic monitoring is the only technique to give an areal view of the reservoir, and injection anomalies from 4D seismic interpretation (3D geobody envelopes) can be used to represent the cumulative injection into a particular zone at the time of the monitor survey. This paper contains illustrations for the comparison of injection split estimates from reservoir quality (logs), well injectivity analysis, production logging, formation pressure testing and 4D seismic monitoring. Consistency between these various data sources reduces uncertainty for important reservoir management and field development decisions (well interventions, infill planning etc.). 4D seismic has proved to be beneficial for the field development and reservoir management of many Angola Block 17 fields and this particular example demonstrates the efficacy of integration of several data sources for effective injection analysis on one such water-flood field.
- Geophysics > Time-Lapse Surveying > Time-Lapse Seismic Surveying (1.00)
- Geophysics > Seismic Surveying (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.41)
Abstract Commonly used Drill-in Fluids (DIF) are typically comprised of starch, xanthan and sized calcium carbonate. Although, DIF is inherently less damaging than the conventional drilling mud, relatively impermeable filter cakes are still deposited on the borehole walls. The polymer in the mud provides cohesiveness and encapsulates the bridging solids (CaCO3). Consequently, the polymers in the cake retard the dissolving of the bridging particles and therefore, must be decomposed to allow a complete and even dissolution of the soluble solids in the filter cake. A common practice to minimize such damage is the application of acids (External Breaker) or strong oxidative breaker (Internal Breaker) system to dissolve filter cake solids and biopolymers. Magnesium Peroxide is an internal breaker. It is a classified oxidizer which slowly decomposes to release oxygen. Since magnesium peroxide is a powdered solid, it becomes an integral part of the filter cake. Due to the extremely low solubility of Magnesium peroxides it remains stable for extended periods of time in alkaline environment and within the filter cake. The magnesium peroxide, when exposed to an acidic solution, it releases hydrogen peroxide which degrades the polysaccharide type polymers and open-up the external filter cake. In an effort to evaluate the effect, laboratory experiment was carried out. Due to the wide range of possible mud system, a pragmatic range was selected for evaluation. A total of six different drill in fluid were formulated, based on practical application in the field. The laboratory experiment shows that magnesium peroxide influences the acid clean up. Subsequent field trial in three horizontal wells in South Oman field showed excellent stability of the mud and clean up after soaking in 15 % hydrochloric acid.
- Europe (0.68)
- North America > United States (0.47)
- Asia > Middle East > Oman (0.25)
Abstract The Tesnus sandstone was deposited during the late-Mississippian/early-Pennsylvanian time in clastic debris flows. In general, it consists of a series of sand/mudstone turbidite sequences that are deposited in thicknesses varying from a few hundred to several thousand feet overall. The uppermost Tesnus consists of amalgamated and thinly-bedded sands that contain poor–good vertical connectivity and tend to have better ultimate recoveries. The lower sands are layered sands consisting of thin interbedded sandstone and shale sequences with poor vertical connectivity. These sands present an analysis problem for conventional open-hole logs, as standard porosity interpretation is not directly related to well performance as a result of the high clay content and poor permeability. Hydrocarbon production from the Tesnus is primarily natural gas with a varying amount of CO2 content, ranging from 1—30%, and very minor amounts of formation water. Sand and shale sequences can be as thin as 1–2 in. These thin zones could have high permeability zones next to zones of no permeability. Thin bed logging approaches were used, but could not adequately measure the volume nor evaluate the quality of the reservoir. Magnetic Resonance logs were added to the typical logging program in an attempt to gain a better understanding of this complexity. The Bray-Smith bin permeability equation was used with the T2 (relaxation) response to accurately define permeability. The presence of hydrocarbon was clearly indicated by the T1 (polarization) response. These answers allowed completions to be targeted in the more productive parts of the Tesnus and enhanced the calculation of net pay. This paper summarizes the results of using these measurements to design completions in this difficult reservoir. This approach can be applied in many difficult evaluation situations.
- 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)
- (21 more...)
Abstract The majority of enhanced oil recovery (EOR) projects are being executed in the the U.S., Canada, Venezuela, Indonesia and China. The volume of oil produced by EOR methods increased considerably from 1.2 MMBD in 1990 to 2.5 MMBD in 2006 (Sandrea and Sandrea 2007). Current total world oil production from EOR is approaching 3 MMBD representing about 3.5% of the daily global oil production (Sandrea and Sandrea 2007). Thermal and CO2 methods are the major contributors to EOR production, followed by hydrocarbon gas injection and chemical EOR. Other more esoteric methods, e.g., microbial, have only been field tested, without any significant quantities being produced on a commercial scale. In recent years, the number of EOR projects has increased with escalating oil prices. The number of EOR projects in the Middle East (ME) has also increased over the past decade. In some countries like Oman, there has been no choice but to implement EOR projects aggressively due to dwindling "easy oil." Other countries in the region have also started to think EOR, and are including them in their strategic short-, medium- and long-term development plans. Furthermore, there are many projects on the drawing board and appropriate screening studies and EOR pilots are being pursued region-wide. This paper reviews the current ME EOR projects from full-field development to field trials, including those on the drawing board. The option of advanced secondary recovery (ASR) — also known as improved oil recovery (IOR) — technologies before full-field deployment of EOR is also discussed. A case is made that they are a better first option before deployment of capital-intensive EOR projects. The ME’s general drive towards "ultimate" oil recovery — instead of immediate oil recovery — is highlighted in the context of EOR. Some of the enablers for EOR in the ME are also discussed in the paper. It highlights the opportunities and challenges of EOR specific to the region.
- Asia > Middle East > Oman > Dhofar Governorate (0.47)
- Africa > Middle East > Egypt > Gulf of Suez (0.29)
- Geology > Rock Type > Sedimentary Rock (0.48)
- Geology > Petroleum Play Type > Unconventional Play (0.48)
- Geophysics > Seismic Surveying (0.68)
- Geophysics > Borehole Geophysics (0.46)
- Asia > Middle East > UAE > Abu Dhabi > Rub' al Khali Basin > Rumaitha Field > Thamama Group Formation (0.99)
- Asia > Middle East > Turkey > Raman Field (0.99)
- Asia > Middle East > Turkey > Dodan Field (0.99)
- (19 more...)
Case Study: The Research Progress of Using Stimulation Technologies in Horizontal Wells to Develop Low-permeability Reservoirs
Jianwen, Yan (China Center for Industrial Security Research, Beijing Jiaotong University, Research Institute of Petroleum Exploration & Development, PetroChina) | Yurong, Zhang (Petroleum Engineering College, Northeast Petroleum University) | Wenjun, Wang (Daqing Oilfield Company Ltd., Petrochina) | Cheng, Cai (Research Institute of Petroleum Exploration & Development, PetroChina) | Na, Zhang (Research Institute of Petroleum Exploration & Development, PetroChina) | Bairu, Shi (Research Institute of Petroleum Exploration & Development, PetroChina)
Abstract In the last three years, the horizontal well technology was developed at high speed in PetroChina, and the number of applications was more than 3000 by the end of 2008. This paper focuses on the stimulation technologies in horizontal wells and the latest research progress of using them to develop low-permeability reservoirs in PetroChina. To solve the problem in the development of low-permeability reservoirs, PetroChina carried out the researches including the adaptability study of drilling horizontal wells in low-permeability reservoirs, the matching relationship study of horizontal wells with different well patterns, the stimulation technologies, such as fundamental acid fracturing technology, staged hydraulic fracturing technology in a perforation completed horizontal well, liquid slug staged fracturing technology, mechanically staged fracturing technology and limited-entry fracturing technology, etc. Several breakthroughs had been made in the key technology research, and the new technology had been applied to 405 wells in field tests, which acquired good effect during 2007 to 2009. After stimulation, the maximum individual well production came up to 4.2 times of the adjacent wells, and a great deal of experience had been accumulated during these tests at the same time which would provide technical support for the application of horizontal wells in the development of low-permeability reservoirs.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > China Government (0.77)
- Asia > China > Shanxi > Ordos Basin > Changqing Field (0.99)
- Asia > China > Shaanxi > Ordos Basin > Changqing Field (0.99)
- Asia > China > Ningxia > Ordos Basin > Changqing Field (0.99)
- (5 more...)
Abstract Unexpected high water cut, sand production and low productivity have negatively affected multiple wells producing from reservoirs in the Apure Area fields of southwest Venezuela. As a result, multiple well interventions have been conducted which increase costs and delay oil production. Several of these wells are inactive today but could be potential candidates for reactivation by reperforating prospective intervals. In several cases, the selection of the perforated interval for these reservoirs is considered inefficient because the effects of multiple dynamic and static petrophysical properties are not considered in the current method, such as vertical permeability, anisotropy or pore throat size, among others. We propose a systematic analysis to optimize the interval to be perforated for inactive and new wells that will minimize such related production problems. The proposed analysis involves the incorporation of multiple variables (type of perforation, interval to perforate, distribution of reservoir fluids, fluid of completion, etc.) to consider the effects of the different petrophysical properties on well productivity. The latter are obtained by integration of rock-core data and conventional and advanced well logs acquired in open and cased hole. In addition, we conducted a sensitivity study to analyze other parameters, such as perforating method and production behavior. A technical analysis was performed to select the optimum design based on different conditions leading to a complete study. The results show that the optimum interval selection and type of perforation to be implemented should not involve only a simple net pay consideration but also multiple factors such as reservoir properties, reservoir fluids distribution and perforating method that play a key role in well production behavior. Finally, we present field applications that confirm the success of this method that enables the reliable selection of an optimized perforated interval.
- South America > Venezuela > Apure (0.70)
- Oceania > Australia > Western Australia > North West Shelf (0.15)
- North America > United States > Texas > Victoria County (0.15)
- Europe > United Kingdom > North Sea > Southern North Sea (0.15)
- Geology > Geological Subdiscipline (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.49)
- South America > Venezuela > Margarita Basin (0.99)
- South America > Venezuela > Falcon Basin (0.99)
- South America > Venezuela > Apure > La Victoria Field > Navay Formation (0.99)
- (2 more...)
Abstract Time-Lapse seismic attributes has been showed as a promising tool to be used in the history matching process. The most common seismic attribute used to integrate these data is P-impedance. The procedure usually made is a minimization of the differences between the seismic P-impedance and the synthetic P-impedance computed from the flow simulation data through a forward modeling. On this paper, we propose a methodology that goes in the opposite way. We invert the seismic data to pressure and saturation and then incorporate these results in the history match procedure in order to integrate the inversion process with the flow simulator, using the results of the reservoir simulation to guide the process. Another feature is that instead of using only the P-impedance in our inversion procedure we are also taking into account a second seismic attribute the S-impedance, which is more sensitive to pressure than saturation variations. A discussion is presented regarding the results obtained using a model with characteristics similar to the Brazilian offshore fields and synthetic seismic data. The main contribution of this work is the integration of the seismic attributes inversion and reservoir simulation processes. We also show the advantages of the inversion procedure to obtain pressure and saturation considering prediction of petroleum production and the details used in the methodology to avoid multiple combinations of saturation and pressure in the inversion process.
- Europe (1.00)
- North America > United States (0.68)
- 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 An Integrated Asset Model (IAM) Project was carried out for the 56 & 88 Blocks of Camisea area. This area is located in the South Ucayali Basin, Peru, within the Sub-Andean fold and thrust belt. Camisea involves three anticlines with three independent world class reservoirs and is one of the most important natural gas and condensate reserves ever discovered in Latin America. The targets of this study were to evaluate: the Field Development Plan, the Scenario Analysis, Conceptual Compression Plan, Monitoring and Surveillance plan. The IAM was used to evaluate the potential development scenarios, and also to optimize production taking into account reservoir performance, surface facility and process plant constraints. The IAM also makes it easier for production and asset managers to diagnose potential problems at an early stage, and thus intervene before production is compromised, and provides an invaluable framework for performance analysis and decision making. Camisea lies within an environmentally sensitive area, which has dictated an offshore-on-land strategy to minimize the number and footprint of the drilling facilities, and also places significant restrictions on the design of compression equipment which will be required to maintain production rates in the future. The IAM was built incorporating the following models and software: a compositional reservoir model, nodal analysis, surface network modelling and process simulation. The individual models were linked together within integration software which enables dynamic linking and controlling of the various packages. The IAM was validated against historical production data and also benchmarked against stand-alone reservoir model predictions. Several development scenarios were then investigated, including: facility debottlenecking, conversion of redundant cycling injector wells to production, compression optimization, and reservoir uncertainty. The IAM was also used to facilitate the economic evaluation of each case.
- South America > Peru > Ucayali Department > Ucayali Basin (0.99)
- South America > Peru > Junín Department > Ucayali Basin (0.99)
- South America > Peru > Cusco Department > Ucayali Basin > San Martin Field (0.94)
- South America > Peru > Cusco Department > Ucayali Basin > Camisea Field (0.89)
Abstract A number of successful case studies are presented in this paper to demonstrate the use of the pressure-rate deconvolution approach to estimating drainage areas for wells completed in some of the naturally fractured tight gas reservoirs of the Canadian Rockies Foothills. This study covers the application of deconvolution to two key carbonate stratigraphical horizons in the area: the Triassic Baldonnel and the Permo-Carboniferous Taylor Flat formations. Our original application of pressure-rate deconvolution was to wells in a major Cretaceous-aged sandstone member, the Cadomin-Nikanassin horizon. This process and results of this original application wil be documented and presented in a separate publication (Jones and Chen, 2011). In these structural plays, the matrix rock properties controlling the gas storativity of these formations are low with porosity between 3% and 6%. Correspondingly matrix rock permeability is also low with values between 0.01 and 0.1 md. However, all of these formations have been thrusted, overturned and have been subjected to reverse faulting. These diagentic factors have created swarms of natural fractures which control flow rates and may define rock volumes connected to individual wells. In each well, a pre-production short flow test for each is performed with the intent of ensuring acceptable flow rates and to scope facility design. At this stage of early development, initial gas in-place (IGIP) estimates are derived from geophysical mapping mainly with plans to calibrate this IGIP number through the application of gas material balance, rate-transient analysis and/or simple late-time rate decline. In recent years, the pressure-rate deconvolution approach has been successfully applied to many of these reservoir pools. The rate history data is available in the early stage of production, which is integrated with pressure buildup data collected later in the production life of a well during annual or routine, relatively short shut-in periods. Application of deconvolution in this paper is aimed at detecting early signs of pseudo-steady state pool depletion and to estimate the connected drainage volume. The case studies presented here compare the deconvolution drainage volumes with the estimates from volumetric IGIP, gas material balance, and rate-transient analysis. The procedures help calibrate and/or reconcile geoscience defined volumetric resource sizes, map remaining reserves and possible infill-drilling opportunities.
- Europe (1.00)
- North America > Canada > British Columbia (0.93)
- North America > United States (0.68)
- Geology > Structural Geology > Fault > Dip-Slip Fault > Reverse Fault (0.34)
- Geology > Geological Subdiscipline > Stratigraphy (0.34)
- Geology > Geological Subdiscipline > Geomechanics (0.34)
- North America > United States > Texas > Meramec Formation > Meramec Formation > Mississippi Chat > Mississippi Lime > St. Louis Formation (0.99)
- North America > United States > Texas > Meramec Formation > Meramec Formation > Mississippi Chat > Meramec Formation > St. Louis Formation (0.99)
- North America > United States > Texas > Meramec Formation > Meramec Formation > Meramec Formation > Mississippi Lime > St. Louis Formation (0.99)
- (34 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Tight gas (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Estimates of resource in place (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)