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Collaborating Authors
Reserves Evaluation
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 148717, ’Effects of Fluid and Rock Properties on Reserves Estimation,’ by Kegang Ling, SPE, Zheng Shen, SPE, Texas A&M University, prepared for the 2011 SPE Eastern Regional Meeting, Columbus, Ohio, 17-19 August. The paper has not been peer reviewed. Precise reserves calculation is fundamental for production forecasting. Great efforts are made to obtain fluid and rock properties such as porosity, permeability, saturation, rock and fluid compressibility, viscosity, fluid gravity, gas z-factor, saturation pressure, reservoir pressure, and temperature. There is always uncertainty regarding the information because of instrument sensitivity and limitations, measurement error, environmental effects, sample interval, location, and how representative of the rock the sample is. A systematic study on the effects of fluid and rock properties on reserves estimation was conducted. Introduction Fluid and rock properties control the volume of original hydrocarbon in place and the recoverable oil and gas. Uncertainty and error exist because of the instrument sensitivity and limitations, measurement error, environmental effects, sample interval, location, and how representative of the rock the sample is. Measuring rock properties under reservoir conditions is very difficult. A synthetic field was built to study the effects of fluid and rock properties. It is an oil field with aquifer support. The initial reservoir pressure is above the bubblepoint pressure. Initially, five producers were drilled to produce oil. With time, reservoir pressure declined. As the reservoir pressure declined below the bubblepoint with production, solution gas was released from oil. When the gas saturation reached critical saturation, it began to flow with the oil and water. This three-phase flow in the reservoir represents the middle and late production periods. Model Description The simulation model divides the reservoir into 93×93×2 gridblocks. The reservoir is modified to an irregular shape by assigning zero porosity and permeability to gridblocks at the reservoir edge. To populate the rock properties, different porosities, permeabilities, depths, and pay thicknesses were assigned to each gridblock. Initially, a uniform oil/water contact divided the porous sand into oil and water zones. Pressure at datum was assigned such that pressure above and below the datum can be calculated according to in-situ fluid density. Initial water saturation was assigned to respect the real oil reservoir. Rock and water compressibilities were incorporated and were assumed to be constant at different pressures. Oil viscosity varied with the pressure because solution gas has a significant effect on it. Water viscosity was kept constant. Oil gravity, gas specific gravity, water specific gravity, formation-volume factor (FVF) for oil and gas, and solution-gas/oil ratio were assigned with values often found in real oil fields.
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 161092, ’A New Approach to Reserves Estimation in Shale-Gas Reservoirs Using Multiple Decline-Curve-Analysis Models,’ by Srikanta Mishra, SPE, Battelle Memorial Institute, prepared for the 2012 SPE Eastern Regional Meeting, Lexington, Kentucky, 3-5 October. The paper has not been peer reviewed. Recent interest in the Marcellus and Utica plays has renewed attention to the problem of reliably estimating recoverable reserves from low-permeability shale-gas formations. Over-optimistic results obtained from the commonly used Arps’ hyperbolic model have led to development of alternative decline-curve-analysis models that are based on empirical considerations (e.g., the Duong power-law model) or mechanistic considerations [e.g., the Valko stretched-exponential-decline model (SEDM)]. This work addressed discriminating between such models (including a new mechanistic model proposed for decline-curve analysis that is based on the Weibull growth curve) with only limited production data. A new approach to aggregating estimated-ultimate-recovery (EUR) forecasts from multiple plausible models is presented. Introduction The use of horizontal drilling, supplemented by multistage hydraulic fracturing, spurred the production of shale gas, including the Barnett, Eagle Ford, Haynesville, Marcellus, and Utica plays. The result is challenges in production forecasting and reserves estimation. Projecting production-decline curves is, perhaps, the single most widely used method for forecasting production from tight gas and shale-gas wells. Future-production potential at any given time and an estimated ultimate recovery (EUR) are assessed by fitting an empirical model of the well’s production-decline trend and by projecting this trend to the well’s economic limit or a common cutoff time (e.g., 30 years). The most commonly used production-decline-curve model is Arps’ hyperbolic model. However, forcing the model to fit production data from shale-gas wells has been found to result in over-optimistic results of EUR, stemming from physically unrealistically high values of the decline exponent to force the fit. Several alternatives have been proposed for analyzing decline curves for tight gas wells. One approach involves constraining the late-time decline rate to a more-realistic value on the basis of experience or analogs. Another approach involves searching for empirical decline-curve models that impose physically meaningful parameter definitions and finite EUR values on model predictions. A key issue associated with the use of multiple models is how to discriminate between them with limited production periods, and how to combine the model results to yield an assessment of uncertainty in reserves estimates.
- North America > United States > West Virginia > Appalachian Basin > Utica Shale Formation (0.94)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Field > Marcellus Shale Formation (0.94)
- North America > United States > Virginia > Appalachian Basin > Marcellus Field > Marcellus Shale Formation (0.94)
- (7 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Production forecasting (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
An Occidental rig working in the Permian Basin of west Texas and New Mexico, an area of high activity for the company in mature field operations. Revitalizing these fields extends their The term mature field does not have a single definition. Individual A 2011 report, "Mature Oil Fields--Unleashing the companies may apply their own definitions. Potential," by IHS Cambridge Energy Research Associates, "We consider the subsurface and the surface," indicated that approximately two-thirds of global daily said Olivier Heugas, a member of the mature field team at average oil production comes from mature fields and that the Total's headquarters near Paris. "For the subsurface, we percentage is increasing over time. Regardless of the definition, mature fields are a huge global resource. With reserves categorized as proved or probable, attempts to expand reserve levels come at a relatively low risk. Modest additions to a base of this size can be very substantial. Revitalizing a mature field means taking measures that increase the value extracted from the field beyond original expectation. Every field has a production curve over which production grows to a peak level and then declines until it reaches the point at which operation is no longer economic. Revitalization extends the natural decline curve to increase ultimate economic hydrocarbon production. A variety of measures may be used, including the application of additional technology to characterize, monitor, and manage the producing reservoir; improve drilling and completions; and boost the recovery factor. Achieving significant cost reduction in field operations, through technology application or more effective work processes and business practices, can also play an important role. Although the aim of revitalization is to boost future production and recovery levels, it is crucial that an operator has first taken the steps to assure that original producible reserves goals are being met. Heugas explained Total's approach to revitalizing mature fields. "First, we must secure what we plan to produce from existing facilities, which are aging," he said. "And for that, we need to implement our development plans effectively for programs such as infill drilling and invest in maintenance.
- 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)
- (61 more...)
- Well Drilling > Drilling Operations (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation (1.00)
- (5 more...)
Management In November, the SPE Oil and Gas Reserves Committee (OGRC) published Guidelines for the Application of the Petroleum Resources Management System (PRMS). The guidelines, available at http://www.spe.org/industry/docs/PRMS_Guidelines_Nov2011.pdf, provide information and examples on the use of PRMS in the classification of oil and gas reserves and resources. The new guidelines replace the 2001 Guidelines for the Evaluation of Petroleum Reserves and Resources. New chapters include “Estimation of Petroleum Resources Using Deterministic Procedures” and “Unconventional Resources.” Other chapters were updated and expanded to reflect current technology and enhanced with examples. The intent of the guidelines is not to provide a comprehensive document that covers all aspects of reserves calculations, but to serve as a useful reference tool for reservoir engineering and reserves evaluation professionals around the world. SPE has been at the forefront in developing common standards for petroleum resource definitions to provide consistency, transparency, and reliability to benefit stakeholders involved in international finance, regulation, and reporting. A milestone in standardization was achieved in 1997 when SPE and the World Petroleum Council (WPC) approved the “Petroleum Reserves Definitions.” Since then, SPE has continuously updated the definitions. In 2007, SPE, WPC, the American Association of Petroleum Geologists (AAPG), and the Society of Petroleum Evaluation Engineers (SPEE) approved the Petroleum Resources Management System, globally known as PRMS. The Society of Exploration Geophysicists (SEG) subsequently endorsed PRMS. PRMS has been acknowledged as the oil and gas industry standard for reference and was used by the US Securities and Exchange Commission as a guide for its updated rules, “Modernization of Oil and Gas Reporting,” published in 2008. SPE recognized that new applications guidelines were required for the PRMS. The SPE Oil and Gas Reserves Committee formed an Applications Guidelines Document Subcommittee in April 2007 to undertake this task. I was honored to be asked to chair the subcommittee. The original 2001 guidelines document was the starting point for this work. The goal was to have an inclusive process where the industry was involved and all stakeholder input was considered fairly by experts.
- Reservoir Description and Dynamics > Reserves Evaluation (1.00)
- Management > Asset and Portfolio Management > Reserves replacement, booking and auditing (1.00)
This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 139376, ’Marlim Field: An Optimization Study on a Mature Field,’ by Dirceu Bampi, Petrobras, and Odair Jose Costa, Halliburton, prepared for the 2010 SPE Latin American & Caribbean Petroleum Engineering Conference, Lima, Peru, 1-3 December. The paper has not been peer reviewed. Giant fields provide a significant portion of the total hydrocarbon production in Brazil. Most of these fields are in advanced exploitation stages. A drainage-optimization study was performed on the Marlim field, a giant and mature field in the Brazilian Campos basin. Reservoir-flow simulations were used to optimize the methodology and increase the recoverable-oil volume by accelerating the oil production. As a result, new-well proposals became more economically attractive. Introduction The Marlim field, discovered in 1985, is in the northeastern part of the Campos basin in water depths between 600 and 1200 m. Reservoir depths are 2500 to 2750 m, with temperatures between 65 and 72°C. Marlim is part of a large complex of reservoirs including the Marlim Sul and Marlim Leste fields. The original oil in place is 1.012×10 std m, and the maximum permeable thickness is 125 m. The reservoir is unconsolidated sand-stone with an average net-/gross-thick-ness ratio of 86%, average porosity of 30%, and permeability of 1 to 10 dar-cies. The petrophysical analysis indicated original water saturation of 15%, saturation pressure of 265 kgf/cm, and residual-oil saturation of 23%. The oil at reservoir conditions has a viscosity of 4–8 cp and gravity of 18–25°API. The reservoir is divided into five stratigraphic zones. Every zone is in hydraulic communication, although, in some areas, the communication is somewhat constrained. The reservoir has small aquifers underlying the oil, and solution-gas drive is the main production mechanism. The reservoir is undergoing a secondary-recovery process by use of seawater injection. Production startup occurred in March 1991, and water injection began in September 1994. Peak production occurred in April 2002 with 9.79×10 m/d. Oil production averaged 4.48×10 m/d, with water cut of 54% in April 2010. The cumulative oil production surpassed 3.18×10 m in April 2010, representing 32% recovery. The field contains more than 200 wells, with 125 in operation and a producer/injector ratio of 1.85. The current reservoir-exploitation stage, with oil-production decline and a significant increase in water production, presents serious challenges in maintaining extraction cost at acceptable levels. To accelerate field oil production and increase the recoverable volume, this simulation-optimization study considered drilling 16 new producing wells and attempted to identify targets for future sidetracks from these new wells.
- 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 > Campos Basin > Campos Field (0.97)
- (2 more...)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Estimates of resource in place (0.88)