Ultimate Recoverable Reserves Research Articles

China's lithium supply chain: Security dynamics and policy countermeasures

This paper used the system dynamics method to model the lithium supply chain in China, which was simultaneously driven by both demand and price dynamics. We focused on the long-term security dynamics in the context of resource constraints and the growing demand for electric vehicles (EVs) in China. We then simulated the impact of the short-term shock caused by the Coronavirus on the security of the domestic lithium supply chain. Based on scenario analysis, China's lithium supply chain exhibited prominent consumption-driven characteristics. Long-term changes in China's ultimate recoverable lithium reserves would not have a significantly impact on lithium supply chain security. Contrary to this, the development of the EVs industry would result in a significant increase in China's demand for lithium, which might adversely affect the security of the country's supply chain for lithium in the future. The domestic lithium supply chain was able to withstand the short-term impact of the Pandemic, but overcapacity was intensified as a result.

Economic Limit Estimation and Production Forecasting in a Field by Using Decline Curve Analysis Method

In this paper, the decline curve analysis method is performed according to a new economic limit in a field named X (for confidential reasons). The production data are processed in EXCEL software and the forecasting is made in MBAL software by respecting the following steps: Firstly, identify the decline zone and determine the decline model on the production history, secondly estimate a new economic limit by using the actual oil price, thirdly, forecast the production and determine the reserves still recoverable and fourthly, make an economic evaluation. The interpretation of the result show that the decline zone is extended on 540 days and the decline curve showed an exponential decline by the next, the new economic limit is estimated at 381.86 Sm3/Day which allow concluding that, the life of the field X is extended from 367 days with 253,935.46 Sm3 as the ultimate recoverable reserves. By the end, these reserves can generate 11,581,676 USD as net income. The above results make it possible to understand the influence of the economic limit and by ricochet the oil price on the lifetime of field X and on its recoverable reserves. Depending on the company, the makeable net income can be set as profitable or nonprofitable. In the positive case this could allow the reopening of the field X.

Studies on natural gas production prediction and risk quantification of Sinian gas reservoir in Sichuan Basin

The Sinian gas reservoir in the Sichuan Basin has the potential for natural gas exploration and development. Production prediction and risk quantification are important in planning of natural gas resources. Ultimate recoverable reserves (URRs) of Sinian gas reservoir are estimated. Hubbert and Gauss models are used to predict the growth trend of production in the gas reservoir. Based on the prediction results, the Monte Carlo simulation is used to calculate the probability of production realization. The evaluation matrix of risk level is established by using indices of production realization probability and dispersion degree for assessing the risk level of natural gas production. The results show that: (1) compared to the Hubbert model, the production prediction results of the Gauss model have higher accuracy. The Sinian gas reservoir will reach peak production of left( {140 - 285} right) times 10^{8} {text{m}}^{3} /{text{a}} in 2036 and will have stable production from 2032 to 2040. By the end of the stable production stage, the URR exploitation degree is about 60% and (2) the Monte Carlo method can be used to obtain the production realization probability for each year. The risk level evaluation matrix can be established by taking the probability of realization and the dispersion degree as evaluation indices, which can provide the systematization of the risk levels. The study can help to better understand the guiding significance for the natural gas exploration and development.

Establishment and application of prediction model of natural gas reserve and production in Sichuan Basin

Research on predicting the growth trend of natural gas reserves and production will help provide a scientific basis for natural gas exploration and development. The metabolically improved modified weight coefficient GM(1,n) method is applied to the multi-cycle Hubbert model to predict the trend of new proven natural gas reserves in the Sichuan Basin. The ultimate recoverable reserves (URR) is introduced as a boundary condition in the production-time series to predict the natural gas production growth. The research results show that: (1) The annual newly added proven natural gas reserves of the Sichuan Basin maintain a multi-cycle growth trend, which will reach the peak reserves in 2034, at which time the proven rate of natural gas will reach 36%. (2) Based on the predicted results of proven reserves, the final recoverable reserves of natural gas are estimated to be 5.25-5.75times {10}^{12}{m}^{3}. The production in 2035 will reach 750-810times {10}^{8}{mathrm{m}}^{3}/mathrm{a}, and production will grow rapidly. The exploration and development of natural gas in the basin will be prospective for a long time.

Production characteristics and sweet-spots mapping of the Upper Devonian–Lower Mississippian Bakken Formation tight oil in southeastern Saskatchewan, Canada

A workflow that helps identify potential production sweet spots in the Middle Bakken tight oil play is proposed based on analysis of large amounts of production data. The proposed approach is a multivariate statistical model that extracts relevant information from a training dataset of production wells to facilitate geological similarity comparison between economic and sub-economic production wells. The model is applied to the Middle Bakken tight oil play in southeastern Saskatchewan. Data screening for diagnostic geological indicators for sweet spots reveals that several geological factors indicative for conventional oil reservoirs seem to work for the Middle Bakken tight oil play as well. These factors include: a) the NE Torqunay-Rocanville Trend serving as a preferred regional migration path for connecting mature source rock in southern Williston Basin and the Middle Bakken tight reservoir in southeastern Saskatchewan; b) the oils in the Bakken tight reservoirs along the U.S. and Canada border are more likely from local matured Bakken source rocks; c) subtle structural components enhancing the convergence of dispersed hydrocarbons over a large area; d) top seal and lateral barrier improving preservation, thus favouring oil productivity; e) orientation of maximum horizontal stress coincident with the direction of the variogram spatial continuity in ultimate recoverable reserves, so the direction of horizontal well has a significant impact on the oil productivity.

Seismic anisotropy estimation of the Talang Akar formation in south Sumatra basin, Indonesia, using ultrasonic tomography in core plugs

Abstract The South Sumatra Basin is one most prolific hydrocarbon provinces in Indonesia (Figure 1) with estimated known petroleum resources of 4.3 billion barrels of oil equivalent (bboe) (Klett et al., 1997). Talang Akar Formation (TAF) is the main source and reservoir rock in the basin (Sarjono and Sardjito, 1989; Sosrowidjojo et al., 1994). It accounts for more than 75% of the cumulative oil production in the province and has approximately 2 bboe ultimate recoverable reserves (Tamtomo et al., 1997).

Quantifying the uncertainty in the ultimate recoverable oil reserves using the Monte Carlo simulation techniques from ‘OWA’ Marginal Field, Onshore Niger Delta, Nigeria

A review on the development of marginal oil fields in Nigeria has now become an important strategic issue if it is to remain amongst the top producers in the global market, and these fields are vast, available all over the Niger Delta. One of the factors that makes a field marginal is the size of its reserves. Stochastic estimation gives a certainty in terms of the possible number of outcomes within the range of input parameters. In this work, four (4) deviated wells and 3D seismic volume (362 inlines and 401 traces) were interpreted for the evaluation of the field. The petrophysical evaluations were interpreted using the Power Log software and the Seismic, Geographix and Petrel softwares. Stochastic reserve estimation was done using Monte Carlo sampling techniques and subjected to uncertainty quantification using the Crystal Ball software by varying distributions and measuring sensitivity impact on the overall reserves. The production profile was predicted based on some assumptions and history matching which result in the overall Expected Ultimate Recovery (EUR). The petrophysical analysis shows the reservoirs to be within the unconsolidated continental Benin Formation denoted as ‘Intra-Benin’ sands, an unconventional reservoir as supposed the normal reservoir rocks within the Agbada Formation. This indicated high porosity (0.28), water resistivity (7 Ω∙m), and water saturation and also inferred Heavy Oil (low API). Nine hydrocarbon sands were identified but only three (B1, D and E), representing shallow, mid and deep reservoirs were further evaluated. 1P and 2P reserve estimates were 4.8 MMBO and 5.7 MMBO for B1; 15.2 MMMscf and 16.4 MMMscf for D; 8.4 MMMscf and 8.8 MMMscf for E respectively. The Monte Carlo simulation of 1,000,000 trials with mainly triangular distribution assumption generated P10, P50, P90 were 6.5 MMBO, 5.6 MMBO and 4.4 MMBO for B1; 17.5 MMMscf, 13.7 MMMscf and 10.8 MMMscf for D; 10.4 MMMscf, 8 MMMscf and 6.1 MMMscf for E respectively. The sensitivity impact of the input parameters were estimated and ranked, and the coefficient of variability ranges within 15% to 20% for the reservoirs indicating that there is a very low level uncertainty of reserve estimation around the P10, P50 and P90 percentiles which could be positive for investment decisions. ‘OWA’ marginal field reflects a typical low reserve (EUR) category found within the Niger Delta basin.

The gas isotope interpretation tool: A novel method to better predict production decline

Production decline prediction is important to understand the performance and life span of oil and gas wells. The most common prediction method is decline curve fitting based on available production rate data. Such data are fit with different equations that extrapolate to future time. However, the parameters are commonly poorly constrained, especially when the production rate data are limited. In this study, we establish a novel gas isotope interpretation tool to better predict the resource quantity and life span of producing gas wells. This tool is based on the evolution of methane carbon isotope ratios (δ13C1) caused by different gas-releasing processes during production. It requires (1) real-time methane carbon isotope ratio data, (2) continuous gas production rate data for a certain period of time, and (3) basic geological and engineering conditions. We successfully applied the production decline prediction tool to a producing shale gas well in the Barnett Shale. We obtained real-time δ13C1 data for approximately 1 yr using our proprietary, field-deployable gas chromatography–infrared isotope ratio analyzer. The prediction in this well from the isotope method showed a total reserve of up to 7.34–7.75 BCF (2.07–2.19 × 108 m3), which was used to constrain the production decline trend of the study well. The measured production rate data were first fit using the Arps equation, which then joined to an exponential decline curve smoothly at approximately 10 yr, such that the cumulative production calculation from integration of the product rate curve equaled to the total reserve predicted by the isotope method. The novel production decline prediction method thus provided important constraint on the future well production and expected ultimate recoverable reserves.

Coal mining in Indonesia: forecasting by the growth curve method

Coal, a fossil fuel energy resource, plays an important role in the economic development of a country and thus, research on the sustainability of long-term coal supply is a continuous challenge, be it the amount of future supply and time of peak production. This study focuses on the outlook and forecasting of Indonesian coal production. The scope of analysis includes current and future resources, reserves, and production of Indonesian coal. To forecast coal production, this study uses two types of growth curves: logistic and Gompertz curves. To obtain more realistic forecasting, the data applied are based on data from each economic coal basin instead of country-level data. Moreover, production forecasting is carried out by applying two scenarios of ultimate recoverable reserves: scenario 1, calculated based on quoted reserves data, and scenario 2, estimated based on the Hubbert linearization theory. The forecasting results are analyzed to choose the most realistic result considering depletion rate and supply anticipation of future coal demand. The most realistic forecast is provided by the Gompertz curve and scenario 1 using quoted reserves data. Coal production is forecast to peak at 485 million tons in 2026.

New Deepwater, High-Pressure GOM Tubular Maximizes Capability, Reduces Cost

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 173034, “New Deepwater, High-Pressure Completion Tubular for Gulf of Mexico Maximizes Combined-Load Capability While Incorporating Proven Cost- Saving Features,” by T. Anderson, C. Fontenot, and R. Davey, Chevron; J. Dugas and B. White, Quail Tools; K.A. Hamilton, C-FER Technologies; and P.S. Beauchamp, L.C. Karlapalem, A. Muradov, and J. N. Brock, NOV Grant Prideco, prepared for the 2015 SPE/IADC Drilling Conference and Exhibition, London, 17–19 March. The paper has not been peer reviewed. A 2-year comprehensive effort to design, test, manufacture, and deploy a new high-pressure completion tubular (CT) for Chevron’s deepwater Gulf of Mexico (GOM) operations is presented. The completion application expected harsh, aggressive loading modes and high pressures to be encountered. The major challenge was to design, test, and manufacture a subsea-completion string that would provide efficient hydraulics during fracturing operations while ensuring mechanical and pressure integrity. Introduction In 2004, the first built-for-purpose CT incorporating a gas-tight, rotary-shouldered connection was developed and deployed in the GOM. Since that time, rotary-shouldered connections have evolved (this evolution is described in detail in the complete paper). Present-day connections offer improved performance, increased torsional capacity, and improved hydraulics, and have created slimmer profiles. Additionally, running and handling characteristics have been improved, providing faster makeup, reduced trip time, and decreased repair cost because of reduced connection damage. However, the need remained to incorporate these technological advancements and benefits into a second-generation CT. CT Requirements In March 2002, the operator drilled the Tahiti 1 well in 4,017 ft of water to a total depth of 28,411 ft. The GOM well was located approximately 190 miles southwest of New Orleans in Green Canyon Block 640. Results from the exploratory well indicated the presence of high- quality reservoir sand with a total net pay of more than 400 ft. Following the results of the exploratory well, two appraisal wells were drilled simultaneously in Green Canyon Blocks 596 and 640. The appraisal program verified the operator’s initial estimates of 400 to 500 million bbl of ultimate recoverable oil reserves, one of the most significant net-pay accumulations recorded in the GOM. Because of the extreme depth and bottomhole pressure of the Tahiti reservoir, the completion and well test required the design of new equipment to successfully perforate, frac pack, and flow test the Tahiti 1 discovery well, including the design and qualification of a perforating and frac-pack CT. The CT requirements included Fishable within the 9?-in. tieback, limiting the connection outer diameter (OD) to 7 in. An inner diameter (ID) of no less than 4¼ in. to provide the desired treating rate during fracturing operations An absolute-internal-working-pressure rating of approximately 29,000 psi to sustain internal pressure and not leak, potentially jeopardizing the frac-pack results An absolute-external-working-pressure rating of approximately 24,500 psi to sustain elevated annulus pressures and not collapse or leak The ability to withstand multiple makeup and breakout cycles while maintaining sealability at pressure to enable multiple trips into the well for cleanout, displacement, perforation, and fracture operations A high-performance metal-to-metal seal that possessed integrity against fluid leak

Effective Technology Strategy for Shale Plays

This paper presents the results of an analysis of the current state of shale play development in the United States to determine the recent advances in the understanding of reservoir behaviors and the most effective uses of new techniques and technologies. It emphasizes reservoir optimization, and the application of new technologies and techniques to reduce costs and to improve recoverability of hydrocarbons to improve ultimate recoverable reserves. It specifically addresses issues of decline curves, stranded pay between laterals, stacked pay logistics, and pad drilling. In addition, the presentation looks at sweet spot optimization, effective investments, hydraulic fracturing, and geomechanics. In a low price environment, with extreme volatility, the paper also examines strategies employed by companies to preserve their assets and recoverable reserves, which include drilling but not completing and alternative stimulation strategies.

Fracture Characterization Technique in Reservoir Simulation of Vertical Fractured CBM Wells

The typical characteristic of stoning band coal seams is of multi-layers and low permeability, so fractured vertical well is usually used in the CBM development of this kind of coal seams. As far as the reservoir simulation of vertical fractured CBM wells is concerned, the fracture characterization technique is of great importance. Taking the vertical fractured pilots in F coal measures of Bowen Basin in Australia as an example, this paper will illustrate the application of fracture characterization technique in reservoir simulation. Its highlight is to scientifically characterize the shape of hydraulic fractures and quantitatively describe the reservoir permeability improvement after fracturing through “MULTX” of grid conductivity with Tartan grid model, thereby determining key parameters for the reservoir simulation of fractured vertical wells and providing a scientific basis for establishing CBM development plan and forecasting ultimate recoverable reserves.

Imminence of peak in US coal production and overestimation of reserves

Coal is the bulwark of US energy production making up about a third of all energy produced and about half of its electricity generation capacity, over the last decade. Current energy policy in the Unites States assumes that there is at least a century of coal remaining within the nation that can be produced at the current rate of consumption. This assumption is based on the large reported coal reserves and resources. We show that, in coal-producing regions and nations, historically reported reserves are generally overestimated by a substantial magnitude. We demonstrate that a similar situation currently exists with US reserves. We forecast future US coal production, in both raw tonnage and energy, using a multi-cyclic logistic model fit to historical production data. Robustness of the model is validated using production data from regions within the US, as well as outside, that have completed a full production cycle. Results from the model indicate maximum raw tonnage coal production will occur in a time window between the years 2009 and 2023, with 2010 being the most likely year of such a maximum. Similarly, energy production from coal will reach a maximum in the years between 2003 and 2018, with 2006 being the most likely year of maximum occurrence. The estimated energy ultimate recoverable reserves (URR) from the logistic model is 2750 quadrillion BTU (2900 EJ) with 1070 quadrillion BTU (1130 EJ) yet to be mined, while the estimated raw tonnage URR is 124 billion short tons (112 Gt) with 52 billion short tons yet (47 Gt) to be mined. This latter value is merely a fifth of the long held estimate of 259 billion short tons (235 Gt).

Exploitation of Shared Hydrocarbon Resources: A Game Theory Analysis

The North Field/South Pars gas condensate field is the world’s largest gas field with an estimated 1800 trillion cubic feet (tcf) of gas in place and 50 billion barrels of gas condensate. The estimated recoverable reserves are 1,260 tcf, accounting for 19% of the world’s recoverable gas reserves [1]. This field is shared by Qatar and Iran with an estimated 3:1 share of the reserves respectively (divided by the maritime border). These estimates are based on static volumetric estimates. However, the ultimate recoverable reserves are dependent on the development schedule implemented by each country. In 2005, Qatar’s government announced a moratorium on further development projects on the north field in 2005 that is expected to extend till at least 2015 after higher than expected pressure depletion [2, 3]. Meanwhile, the Iranian government has called for and implemented rapid development of their share of the field, the South Pars. This example showcases the interesting nature of the shared resource development task to be analyzed using the principles of game theory. In general terms, since the ultimate recovery of each player (resource owner) depends on their individual production schedule, the situation presents a ‘first-mover advantage’ scenario. It is possible for either player to produce their share of the resource as soon as possible leading to rapid pressure depletion, it would not be illegal to do so. However, the depleted pressure would make development of the other player’s share of the resource uneconomical. The goal of the proposed paper is to study possible strategies and outcomes for exploitation of such shared hydrocarbon resources. The players involved may include resource owners such as land owners or countries and the strategies involved can be cooperative or non-cooperative. In the case of cooperative production strategies, also known as unitization, methods for profit sharing are also discussed.

Analysis of Production Characteristics and Prediction of Recovery of Lianhua Oil Layer in Qi 3-17-5 Block

Through thirty years of development, Lianhua oil reservoir has entered into the stage of low-speed development. At present, the rate of oil production is only 0.0033%. Firstly, it divided development stage of Lianhua reservoir and analyzed production characteristics of each stage. By mean of the production decline curve, it predicted the recovery of the reservoir to estimate the ultimate recoverable reserves and the recovery percent. The results show that the ultimate recoverable reserves of Lianhua reservoir was about 50.813×104 t, the ultimate recovery was 13.177%, the recovery percent of recoverable reserves had reached up to 95.094%, and the remaining recoverable reserves were rare. Therefore, it urgently needs to find a more reasonable development model to do secondary development of Lianhua reservoir. The conclusions have an important realistic significance of guiding secondary development of the Lianhua reservoir.

An analysis of China's coal supply and its impact on China's future economic growth

Many people believe that China's economic growth can continue almost indefinitely. For a manufacturing-based economy such as China's to continue to grow, it needs an adequate supply of inexpensive energy. To date, this energy growth has primarily come from coal, but China's indigenous coal supplies are now falling short of the amount needed to support this growth. In this situation, the status of China's future coal supply will be very important for China's future economic development. Our analysis shows that China's ultimate recoverable coal reserves equal 223.6×109MT, and its production will peak between 2025 and 2030, with peak production of approximately 3.9×109MT. The extent to which China can import coal in the future is uncertain. With rising coal demand, this combination is likely to create a significant challenge to China's future economic development.

Forecast of oil reserves and production in Daqing oilfield of China

As China’ largest oilfield, Daqing is of great importance to China, this paper analyzes the status of the Daqing oilfield and forecasts its ultimate recoverable reserves by use of the URR model. The forecast results are presented for three scenarios which show that the ultimate recoverable reserves in Daqing oilfield are 3574.0 million tons in the optimistic scenario, 3169.3 million in the base case scenario and 3033.3 million in the pessimistic scenario, respectively. A system dynamics model is established and the quantitative relationships between variables in the model are determined. Total oil production, remaining recoverable reserves, annual newly discovered reserves, and the degree of reserves recovery before 2060 are simulated under the three scenarios by use of the system dynamics model. The forecast results show that the future oil production in Daqing oilfield will continue declining, under the base case scenario, from 41.6 million tons in 2007 to 8.0 million tons in 2060. For Chinese policy-makers, it is worth paying attention to the problem of whether oil production in new oilfields can effectively make up for the decline in production of the large, old oilfields.

An integrated approach to energy prospects for North America and the rest of the world

Many international organizations and research institutions have released recently unequivocal scenarios on energy's future prospects. The peak in global oil production is likely to happen in the next ten to fifteen years, if it hasn't already happened, and decisions to be made in the near future are likely to have large impacts on our quality of life in the coming decades. This study presents an integrated tool for national energy planning customized to North America. The authors analyzed the impact of world oil production on economic, social and environmental indicators. Two cases of global ultimate recoverable oil reserves are considered, a low and medium estimate within current research. Three sets of policy directions were chosen: Business As Usual (Market Based), Maximum Push for Renewables, and Low Carbon Emissions. Results of the simulations show that without restrictions on emissions coal becomes the dominant energy in the longer term. On the other hand, if US policymakers are able to effectively implement the necessary polices, such as a 20% RPS by 2020 and increased CAFE Standards, along with increased energy conservation and efficiency, the medium to longer-term economic impacts of a global peak in oil production can be mitigated, while a sustained reduction in emissions would require a larger effort.

The Importance of Initial Reservoir Pressure for Tight Gas Completions and Long-Term Production Forecasting

Abstract Flow and buildup testing of gas wells in Alberta is common practice for the determination of reservoir pressure, permeability and wellbore skin. Post-frac welltesting is still regarded as the preferred welltesting method, due in part to current government regulations for initial testing requirements. With the maturing of the Western Canadian Sedimentary Basin (WCSB) in recent years, the development of unconventional gas reservoirs has significantly increased. Deep tight gas reservoirs have become an important part of unconventional gas resources and this paper will address several issues and pitfalls related to the welltesting of tight gas. Initial reservoir pressure is probably one of the most important ‘data points’ for reservoir engineering and completion design and yet one of the most abused and assumed parameters. Field examples will highlight major errors that are likely to occur when post-frac flow and buildup tests are analyzed for tight gas reservoirs without precise knowledge of the initial reservoir pressure. This paper will demonstrate that errors of reservoir pressure as small as 2% can lead to significant overestimates of the well 's recoverable reserves. Introduction The strong commodity prices in the energy sector experienced in recent years have resulted in an increased activity level for the development of unconventional tight gas reservoirs. Natural gas price is the major factor that will determine the economic viability of tight gas reservoirs. However, there are additional factors that should be taken into consideration, such as original-gas-in-place, completion efficiency, well spacing and the ultimate recoverable reserves. Unlike conventional gas reservoirs where proven reservoir engineering techniques are easily applied, the predictability of deep tight gas reservoirs is much more difficult to achieve. Too often the post-frac welltest results from wells completed in tight gas reservoirs are used to establish initial pressure, completion effectiveness and reservoir permeability for production forecasting for economic decisions. The flow behaviour of hydraulically fractured tight gas reservoirs is very complex and significant errors in the determination of matrix permeability and fracture parameters often occur. These errors can have a significant impact on predicting gas production and total cumulative gas recovery. Discussion With the maturing of the WCSB and high natural gas prices, the activity levels in the oil and gas industry have increased to record levels. So has an increased number of tight gas well completions. Generally speaking, performance evaluation of tight gas wells reveals a trend where the production performance of the wells is much less than what was initially predicted. These errors are considered the result of overestimating reservoir parameters such as the reservoir flow capacity (kh). Short references will be made to some of the factors determining the success of developing a tight gas resource:Original-gas-in-place (OGIP) is usually determined by the volumetric method and requires knowledge of reservoir pressure, mapping and petrophysical parameters. One equation used for estimating OGIP is:Equation (1) (Available In Full Paper)Hydraulic fracturing is a necessary step in the completion process in tight gas reservoirs in order to achieve commercial production.

8-7 世界原油生産キャパシティ予測における埋蔵量変化の感度分析((2)評価・経済2,Session 8 エネルギー評価・経済,研究発表(口頭発表))

8-7 世界原油生産キャパシティ予測における埋蔵量変化の感度分析((2)評価・経済2,Session 8 エネルギー評価・経済,研究発表(口頭発表))