Determining the Recoverable Geothermal Resources Using a Numerical Thermo-Hydraulic Coupled Modeling in Geothermal Reservoirs

Recoverable geothermal resources are very important for geothermal development and utilization. Generally, the recovery factor is a measure of available geothermal resources in a geothermal field. However, it has been a pre-determined ratio in practice and sustainable utilization of geothermal resources was not considered in the previous calculation of recoverable resources. In this work, we have attempted to develop a method to calculate recoverable geothermal resources based on a numerical thermo-hydraulic coupled modeling of a geothermal reservoir under exploitation, with an assumption of sustainability. Taking a geothermal reservoir as an example, we demonstrate the effectiveness of the method. The recoverable geothermal resources are 6.85 × 1018 J assuming a lifetime of 100 years in a well doublet pattern for geothermal heating. We further discuss the influence of well spacing on the recoverable resources. It is found that 600 m is the optimal well spacing with maximum extracted energy that conforms to the limit of the pressure drop and no temperature drop in the production well. Under the uniform well distribution pattern for sustainable exploitation, the recovery factor is 26.2%, which is higher than the previous value of 15% when depending only on lithology. The proposed method for calculating the recoverable geothermal resources is instructive for making decisions for sustainable exploitation.

20 Years of Horizontal Multistage Completions: A Summary of Industry Evolution in Unconventional and Conventional Plays

In the past two decades, the advent of the Shale Gas Revolution (SGR) was made possible by the visionary idea that hydrocarbons contained in ultra-low permeability source rocks could be extracted using available technology. Usually, these hydrocarbons take geological time to migrate to higher permeability reservoir rocks until the right structural conditions evolve to extract as recoverable resources. However, paradigm shifts in drilling and completion engineering have enabled unlocking resources from these ultra-tight formations. The innovative idea at the base of this industrial revolution was the combination of horizontal well drilling and hydraulic fracturing, which allowed increasing the surface area available for hydrocarbon flow and overcame the slow and shallow hydrocarbon release from the source rock. This approach can be considered as a bridge between petroleum engineering based on radial diffusivity equation and mining engineering based on physically accessing and extracting the resource. To achieve the high number of hydraulic fractures needed for economical production, different execution techniques evolved and developed in what is known as horizontal multistage fracturing (HMSF) completions. Although HMSF is indescribably linked to SGR, it was surprisingly applied in tight gas formation and offshore sand control applications more than 30 or 40 years ago. SGR contributed to the fast development of new innovative systems engineered and deployed at scale all over North America land operations and was subsequently exported internationally in conventional, unconventional, land, and offshore applications. This paper will cover the most common HMSF completion systems types with a primary focus on unconventionals. It will encompass the evolution of these systems over the past several decades. It will also explore the opportunity case for conventional, and high permeability plays through a series of theoretical and real examples.

Five Decades Of Petroleum Exploration And Discovery In The Malay Basin (1968-2018) And Remaining Potential

Since the first oil discovery in the Malay Basin in 1969, more than 700 exploratory wells have been drilled. To date, there are more than 181 oil and gas discoveries, about half of which are currently in production and about a dozen are already in their secondary or tertiary recovery stages. In 2014 it was estimated that a total of over 14.8 billion barrels of oil equivalent (bboe) of recoverable hydrocarbon resource have been discovered in the basin, contributing to approximately 40% of the total hydrocarbon resources of Malaysia. By the end of the first decade of exploration in 1979, all the major basin-centre anticlinal structures had been tested. This play type contributed 60% of the total discovered resource in the basin. By 1981 this most prolific play type had been practically exhausted, as all the giant fields (those with recoverable resource > 0.5 bboe) had been found. As “creaming” of the basin-centre anticlinal play continued into the early 1980s, exploration efforts gradually shifted to the newly discovered western margin play types, particularly in the Western Hinge Fault Zone, Tenggol Arch and the adjacent Penyu Basin. There was a “lull” period from 1985 to about 1990, due to the global oil crisis, after which exploration was rejuvenated through significant discoveries in several play types on the northeastern ramp margin. This followed a successful drilling campaign that lasted until around 1997 and contributed an additional ~1 bboe of recoverable resources over a seven-year period. Since then, most of the incremental resource addition came from the highly gas-charged play in northern region that comes under the Malaysia-Thai Joint Development Area (JDA) and on the northeastern ramp margin, which includes the Commercial Arrangement Area (CAA) between Malaysia and Vietnam. Individually, however, the hydrocarbon volumes in these later discoveries were relatively small compared to the earlier discovered play types. Subsequently, new play types were pursued, including stratigraphic channels, deeper reservoirs beneath existing fields, high pressure/high temperature (HPHT) reservoirs, overpressured and tight reservoirs, and fractured basement reservoirs. All had some measure of success but none were able to volumetrically match the discoveries made decades earlier. As of end of 2018, over 2100 exploration and development wells had been drilled in the entire basin. Based on the creaming curve, since around 1990 and into the fifth decade of exploration, the incremental resource addition has been increasing steadily at an average rate of ca. 120 MMboe per year. The data indicate that the expected average discovery size would be less than 25 MMboe, and that at least 5 wells need to be drilled per year to sustain the same rate of resource addition. If no new plays are explored and no significant discoveries made, resource addition is expected to plateau beyond 2020. The basin needs a new stimulus, and more importantly, new exploration play concepts to sustain exploration business.

An Integrated Workflow for Reserves Evaluation in the U.S. Permian Basin Based on SPEE Monograph 3

In 2011, the Society of Petroleum Evaluation Engineers (SPEE) published Monograph 3 as an industry guideline for reserves evaluation of unconventionals, especially for probabilistic approaches. This paper illustrates the workflow recommended by Monograph 3. The authors also point out some dilemmas one may encounter when applying the guidelines. Finally, the authors suggest remedies to mitigate limitations and improve the utility of the approach. This case study includes about 300 producing shale wells in the Permian Basin. Referring to Monograph 3, analogous wells were identified based on location, geology, drilling-and-completion (D&C) technology; Technically Recoverable Resources (TRRs) of these analogous wells were then evaluated by Decline Curve Analysis (DCA). Next, five type-wells were developed with different statistical characteristics. Lastly, a number of drilling opportunities were identified and, consequently, a Monte Carlo simulation was conducted to develop a statistical distribution for undeveloped locations in each type-well area. The authors demonstrated the use of probit plots and demonstrated the binning strategy, which could best represent the study area. The authors tuned the binning strategy based on multiple yardsticks, including median values of normalized TRRs per lateral length, slopes of the distribution lines in lognormal plots, ratios of P10 over P90, and well counts in each type-well category in addition to other variables. The binning trials were based on different geographic areas, producing reservoirs, and operators, and included the relatively new concept of a "learning curve" introduced by the Society of Petroleum Engineers (SPE) 2018 Petroleum Resources Management System (PRMS). To the best of the authors’ knowledge, this paper represents the first published case study to factor in the "learning curves" method. This paper automated the illustrated workflow through coded database queries or manipulation, which resulted in high efficiencies for multiple trials on binning strategy. The demonstrated case study illustrates valid decision-making processes based on data analytics. The case study further identifies methods to eliminate bias, and present independent objective reserves evaluations. Most of the challenges and situations herein are not fully addressed in Monograph 3 and are not documented in the regulations of the U.S. Security and Exchange Commission (SEC) or in the PRMS guidelines. While there may be differing approaches, and some analysts may prefer alternate methods, the authors believe that the items presented herein will benefit many who are starting to incorporate Monograph 3 in their work process. The authors hope that this paper will encourage additional discussion in our industry.

Projecting the global impact of fossil fuel production from the Former Soviet Union

Detailed projections of the Former Soviet Union (FSU) fossil fuel production has been created. Russian production has been modelled at the region (oblast) level where possible. The projections were made using the Geologic Resource Supply-Demand Model (GeRS-DeMo). Low, Best Guess and High scenarios were created. FSU fossil fuels are projected to peak between 2027 and 2087 with the range due to spread of Ultimately Recoverable Resources (URR) values used. The Best Guess (BG) scenario anticipates FSU will peak in 2087 with production over 170 EJ per year. The FSU projections were combined with rest of the world projections (Mohr et al. 2015b), the emissions from the High scenario for the world are similar to the IPCC A1 AIM scenario.

20 Years of Independent Oil and Gas Audits: The Trinidad and Tobago Story

Over the 20 year period from 2001 to 2020, the Ministry of Energy and Energy Industries (MEEI) of Trinidad and Tobago commissioned 19 gas and 3 oil audits conducted by independent consultants. Trinidad and Tobago's natural gas Technically Recoverable Resources (TRR) moved from a P1+C1 TRR to Production Ratio of greater than 30 in 2001 to less than 10 years as production has grown from a low of 1.5 Bcf/d to a high of 4.3 Bcf/d. Despite this, the opening of a new exploration basin in the Deepwater has resulted in greater than 100% technically recoverable resource replacement in the last three years for natural gas and a 770% increase in Prospective Resources for crude oil. The data from these successful audits have served to demonstrate the astute management by the Government and People of Trinidad and Tobago of the country's hydrocarbon resources.

Reduced Use of Fossil Fuels can Reduce Supply of Critical Resources

Previous research has identified that climate change mitigation policies could increase demand for resources perceived as critical, because these are used in many renewable energy technologies. This study assesses how reducing the extraction and use of fossil fuels could affect the supply of (i) elements jointly produced with fossil fuels and (ii) elements jointly produced with a host that is currently mainly used in fossil fuel supply chains. Several critical resources are identified for which supply potential from current sources is likely to decline. Some of these, e.g. germanium and vanadium, have uses in low-carbon energy systems. Renewable energy transitions can thus simultaneously increase demand and reduce supply of critical elements. The problem is greatest for technology groups in which by-products are more difficult to recycle than the host. Photovoltaic cell technology stands out as one such group. Phasing out fossil fuels has the potential to reduce both the supply potential (i.e. primary flow) and recoverable resources (i.e. stock) of materials involved in such technology groups. Further studies could examine possibilities to increase recovery rates, extract jointly produced resources independently of hosts and how the geographical distribution of by-product supply sources might change if fossil fuel extraction is scaled back.