Hydrocarbon Assets Research Articles

Construction of g-CN/SnSe nanocomposite through a hydrothermal approach for enhanced OER study

Concerning environmental issues, including global warming and the reduction of hydrocarbon assets, the utilization of environmentally sustainable energy production is imperative nowadays. In this regard, water electrolysis is considered the most prominent and ecologically sustainable technique for the production of hydrogen. However, owing to its sluggish OER, designing electrode materials with remarkable efficiency becomes crucial for boosting the functioning of water electrolysis. In the present investigation, we successfully developed the SnSe catalyst incorporated into graphitic carbon nitride (g-CN) via a simple hydrothermal approach. The various approaches were used to characterize g-CN/SnSe nanocomposite. Meanwhile, g-CN/SnSe nanocomposite demonstrated exceptional catalytic properties for OER under 1.0 M alkaline electrolyte (KOH), which exhibited low overpotential (241 mV) to obtain ideal j (10 mA cm−2) and an exceptional stability (20 h). It also demonstrated a low onset potential (1.27 V), a significant electrochemical active surface area (ECSA) of 592.5 cm2 and an impressive Tafel value (38 mV dec−1), significantly superior to the pure SnSe nanomaterial. The observed improved performance can be attributed to enhanced morphological properties and significant surface area. The above-reported nanocomposite (g-CN/SnSe) shows great potential for OER and other electrochemical systems because of its numerous active sites, faster electron transfer process, exceptional durability and good electrical conductivity.

Investor compensation for oil and gas phase out decisions: aligning valuation methods to decarbonization

ABSTRACT Decisions by states to cancel oil and gas licenses in the transition to net-zero emissions can trigger investment arbitration claims. Given the massive damages that arbitration tribunals can award to investors, investment arbitration is increasingly being criticized as an obstacle to climate change mitigation and the just energy transition. Under the Discounted Cash Flow (DCF) method, tribunals have based their valuation on the expected production volumes during the remaining lifetime of oilfields and forecasts of international oil prices, essentially requiring states to compensate companies at market conditions for all energy left underground. With an increasing number of carbon neutrality pledges at the global level and states’ due diligence obligation to reduce emissions, this article argues that tribunals can no longer ignore decarbonization considerations in the application of the DCF method. Damages decisions must instead account for the price, production cost and risk expectations under net-zero pathways. Significant downward adjustments to the estimated future income of hydrocarbon assets can be achieved by using the lower oil price forecasts in net-zero emissions scenarios, instead of current market conditions. Adjusting future cash flow projections and the discount rate to reflect carbon pricing and other climate policy risks can significantly lower the present value of hydrocarbon assets. As arbitration tribunals have so far ignored decarbonization in their oil damages calculations, legal reforms are needed to require the alignment of investor compensation to decarbonization and ensure a just energy transition.

Origins of pressure dependent permeability in unconventional hydrocarbon reservoirs

Unconventional hydrocarbon assets represent a rapidly expanding proportion of North American oil and gas production. Similar to the incipient phase of conventional oil production at the turn of the twentieth century, there are ample opportunities to improve production efficiency. In this work we demonstrate that pressure dependent permeability degradation exhibited by unconventional reservoir materials is due to the mechanical response of a few commonly encountered microstructural constituents. In particular, the mechanical response of unconventional reservoir materials may be conceptualized as the superposed deformation of matrix (or ~ cylindrical/spherical), and compliant (or slit) pores. The former are representative of pores in a granular medium or a cemented sandstone, while the latter represent pores in an aligned clay compact or a microcrack. As a result of this simplicity, we demonstrate that permeability degradation is accounted for through a weighted superposition of conventional permeability models for these pore architectures. This approach permits us to conclude that the most severe pressure dependence is due to imperceptible bedding parallel delamination cracks in the oil bearing argillaceous (clay-rich) mudstones. Finally, we demonstrate that these delaminations tend to populate layers that are enriched with organic carbon. These findings are a basis for improving recovery factors through the development of new completion techniques to exploit, then mitigate pressure dependent permeability in practice.

Saudi Arabia Case Study Illustrates Road to Zero Routine Gas Flaring

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 21182, “The Road to Zero Routine Gas Flaring: A Case Study From Saudi Arabia,” by Majed Alsuwailem, KAPSARC. The paper has not been peer reviewed. Copyright 2021 International Petroleum Technology Conference. Reproduced by permission. _ The complete paper discusses Saudi Arabia’s progress in gas flaring, the measures the government has taken, and how operators have adapted. It also identifies many lessons learned and technological solutions that could be scaled up on a national or a corporate level to reduce gas flaring to achieve zero routine flaring targets, especially in cases where the state owns hydrocarbon assets and leases them to private operators. History of Gas Flaring in Saudi Arabia Following the discovery in 1948 of Ghawar, Saudi Arabia’s largest oil field, oil production in the country increased and more associated gas was produced and flared. The national oil company, Saudi Aramco, had no interest in capturing gas produced from its oil operations. No local or regional market for it existed, and exporting the gas would have required substantial infrastructure investments. This coincided with periods of low crude oil prices that made gas projects uneconomical. However, as the 1960s and ’70s passed, gas came to be increasingly regarded as an essential part of a broader attempt to diversify the Saudi economy. This, in return, allowed the creation of jobs in new frontiers, including the refining and petrochemical industries. In the early 1970s, the Saudi Ministry of Petroleum and Minerals contracted the Texas Eastern Corporation to conduct a technical and economic feasibility study. It evaluated the benefits of establishing a massive refining and petrochemical industry in the city of Jubail on the Arabian Gulf and Yanbu on the Red Sea, with gas as an important feedstock. The study required major capital expenditures on midstream oil operations. Saudi Aramco, on the other hand, proposed exploiting associated gas to generate electricity. Because the price of oil did not exceed $3/bbl before the 1970s, the Saudi government opted for the first option. Saudi Aramco, however, only foresaw an opportunity in this development if the government contributed major capital to the midstream, resulting in a positive outcome for both the stakeholders and the operator, which turned out to be the case. Master Gas System (MGS) The government gave Saudi Aramco a contract to establish the $12 billion MGS to capture, process, and use gas as fuel and feedstock for the petrochemical plants. Most of this project was paid for by the government. By the fall of 1982, the key components of the MGS (gas-gathering and -processing facilities and pipelines) were fully operational. The MGS saved 4.2 billion scf of gas from being flared, which prevented 80 million tonnes of carbon dioxide from being emitted into the atmosphere annually. Over time, the MGS has been expanded as more oil and nonassociated gas fields have been placed onstream and as demand has risen for dry gas in the power sector. By 2018, the MGS had gathered almost 3.5 trillion ft3/yr and is one of the world’s largest single hydrocarbon networks. It includes 4,000 km of pipelines, 50 gas/oil separation plants (GOSPs), seven gas plants, and two natural gas/liquid units.

Statistical distribution of geomechanical properties and ‘Sweet Spots’ identification in part of the upper Bakken

Completions and Reservoir Quality are two key attributes that are used to characterize nonconventional hydrocarbon assets. This is because, for optimum exploitation of these unconventional assets, horizontal wells need to be drilled in “Sweet Spots” (i.e., regions where Completions and Reservoir Quality are both superior). One way to quantify these qualities is to use reservoir and geomechanical properties. These properties can be estimated on a location basis from well logs, and then mapped over terrain using geostatistical modeling. This study presents a ‘Sweet Spots’ identification workflow based on three performance indexes (Storage Potential Index, Brittleness Index, and Horizontal Stress Index) that can be used to quantify CQ and RQ. The performance indexes are computed from petrophysical property volumes (of Young's Modulus, Bulk Modulus, Shear Modulus, Poisson's Ratio, Minimum Horizontal Stress, Volume of Shale, Total Organic Carbon, Thickness, and Porosity) which are in turn computed from well logs and geostatistical simulation. In the end, the study offers a method to compare the predicted “Sweet Spots” against available production data via their correlation coefficient. The resulting reasonable formation property maps, the successful identification of ‘Sweet Spots’, and a correlation coefficient of 0.88 (between the predicted “Sweet Spots” and well production data) point to the potential of the proposed effort.

Machine learning for recovery factor estimation of an oil reservoir: A tool for derisking at a hydrocarbon asset evaluation

Well-known oil recovery factor estimation techniques such as analogy, volumetric calculations, material balance, decline curve analysis, hydrodynamic simulations have certain limitations. Those techniques are time-consuming, and require specific data and expert knowledge. Besides, though uncertainty estimation is highly desirable for this problem, the methods above do not include this by default. In this work, we present a data-driven technique for oil recovery factor (limited to water flooding) estimation using reservoir parameters and representative statistics. We apply advanced machine learning methods to historical worldwide oilfields datasets (more than 2000 oil reservoirs). The data-driven model might be used as a general tool for rapid and completely objective estimation of the oil recovery factor. In addition, it includes the ability to work with partial input data and to estimate the prediction interval of the oil recovery factor. We perform the evaluation in terms of accuracy and prediction intervals coverage for several tree-based machine learning techniques in application to the following two cases: (1) using parameters only related to geometry, geology, transport, storage and fluid properties, (2) using an extended set of parameters including development and production data. For both cases, the model proved itself to be robust and reliable. We conclude that the proposed data-driven approach overcomes several limitations of the traditional methods and is suitable for rapid, reliable and objective estimation of oil recovery factor for hydrocarbon reservoir.

Modeling the Chance of Commerciality of Petroleum Assets for Economic Development

The chance to discover hydrocarbon volumes of economic quantity diminishes with progressive discovery in explored basins. Given the preponderance of smaller deposits in extensively explored basins and the cost implications of discovering deposits less than the required Minimum Economic Reserves (MER), explorationists and investors in exploration activities need a framework to evaluate the chance of a successful petroleum resources discovery to minimize the risk of unsuccessful exploration. This study develops a new framework to evaluate the chance of discovery of at least a minimum economic reserves volume in an extensively explored basin. It leverages on the postulation for the determination of probability of hydrocarbon economic success as a building block for the new framework. The model combines the concepts of Minimum Economic Reserves, Discovery Efficiency and Probability to derive an explicit analytical function for discovery efficiency and hydrocarbon probability for a commercial discovery. It digitalizes existing Risk Table to ease the complexity to obtain geological chance of success and hydrocarbon asset evaluation for commerciality. Nine Case studies from the prolific Niger Delta basin of Nigeria are used to validate the model. The result of the semi-digital solution of the model shows that three of the studied cases are commercial whereas the remaining six cases are sub-commercial. The study recommends the application of the new framework for hydrocarbon asset evaluation for chance of commerciality to complement models like the cream off curve to predict chance of commercial discovery of hydrocarbon assets.

Technology Focus: Natural Gas Processing and Handling (April 2020)

Technology Focus In 2019, the US experienced the lowest natural gas prices since 2016. This was despite natural gas consumption increasing in the residential and commercial sector by 2% (between October and December) according to the US Energy Information Administration (EIA). In July and August, the electric generation sector also experienced an increase in natural gas consumption because of above-average humidity levels in the Midwest and Northeast. Natural gas inventories at the end of March recorded the lowest levels since 2014 during withdrawal season, whereas the injection season recorded the second-highest levels from sustained growth in natural gas production. This trend of low gas prices was because of natural gas production growth, as prices continued to decline through the rest of 2019. The EIA forecasts an increase in natural gas consumption by 1.4 Bcf/D (1.7%) in 2020. The average US natural gas price is projected to fall by 9% to $2.33/million British thermal units (MMBtu) in 2020. The EIA said it expects continued growth in natural gas production in 2020 in response to improved drilling, increased associated gas production, and increased Appalachian and Permian pipeline take-away capacity. As of 3 February, Henry Hub spot price closed at $1.82/MMBtu, $0.87 lower than the same time last year. Weather temperatures were warmer than expected, except in the Northeast and Midwest where it was colder than expected, hence affecting winter demand. Globally, the Paris-based International Energy Agency’s 5-year forecast shows natural gas demand driven by Asia-Pacific growth, with the region accounting for approximately 60% of the total gas consumption forecasted increase through 2024. China is expected to be at the forefront of this demand growth because it is expected to constitute approximately 40% of the total gas demand increase through 2024. The global liquefied petroleum gas (LPG) market has continued to grow reasonably in the past decade, and the US, as a result of its strong domestic LPG production, has ascended in recent years as the largest LPG producer and exporter in the world. The Asia-Pacific region, because of its growing population, constitutes the highest market share of the global LPG consumption. The global LPG market trend is predominantly supply-driven by natural gas and crude oil but not so much from refining. According to IHS Markit, LPG demand in Asia-Pacific grew approximately 3.5% in 2018 and has continued to maintain its steady growth in 2019. Global supplies of LPG are expected to rise approximately 5% to 325 million tonnes in 2020. By region, approximately 28% of the global supplies will be from the US and approximately 20% from the Middle East. Asia-Pacific will continue to be the main driver for LPG demand growth, accounting for approximately 45% (4.6 million B/D) of the global demand. The prominent increase in US LPG exports has resulted in significant changes in the LPG global trade flow patterns in recent years, demonstrating a shift from a dependency on exports from the Middle East. More can be learned by attending the SPE Annual Technical Conference and Exhibition in Denver on 5–7 October and the SPE Asia Pacific Oil and Gas Conference and Exhibition in Perth, Australia, on 8–11 September. Recommended additional reading at OnePetro: www.onepetro.org. SPE 195759 Solutions for Seal Gas Leakage Recovery in Methane Compression: Integration Into Processing Lines or Gas Valorization Systems by Filippo Conforti, Baker Hughes, et al. SPE 197582 Running Sour Hydrocarbon Assets: Eni’s Story of Experience by Luciano Scataglini, Eni, et al. SPE 195555 Experimental Investigation of Integrity Issues of Underground Gas Storage Containing Hydrogen by Erik Clemens Boersheim, Clausthal University of Technology, et al.

The rise of renewables and energy transition: what adaptation strategy exists for oil companies and oil-exporting countries?

The energy landscape is changing rapidly with far-reaching implications for the global energy industry and actors, including oil companies and oil-exporting countries. These rapid changes introduce multidimensional uncertainty, the most important of which is the speed of the transition. While the transformation of the energy system is rapid in certain regions of the world, such as Europe, the speed of the global energy transition remains highly uncertain. It is also difficult to define the end game (which technology will win and what the final energy mix will be), as the outcome of transition is likely to vary across regions. In this context, oil companies are facing a strategic dilemma: attempt the risky transition to low-carbon technologies by moving beyond their core business or just focus on maximising their return from their hydrocarbon assets. We argue that, due to the high uncertainty, oil companies need to develop strategies that are likely to be successful under a wide set of possible future market conditions. Furthermore, the designed strategies need to be flexible and evolve quickly in response to anticipated changes in the market. For oil-exporting countries, there is no trade-off involved in renewable deployment as such investments can liberate oil and gas for export markets, improving the economics of domestic renewables projects. In the long run, however, the main challenge for many oil countries is economic and income diversification as this represents the ultimate safeguard against the energy transition. Whether or not these countries succeed in their goal of achieving a diversified economy and revenue base has implications for investment in the oil sector and oil prices and consequently for the speed of the global energy transition.

The Sufficiency of Deep Hydrocarbons in the South Caspian Region for Turkey and European Union

The Caspian Sea region did not appear as an important hydrocarbon province during the Soviet Union. This is because that Soviet Russia has very rich and exploitable oil and gas reserves in areas outside the Caspian region. The Caspian Sea coastal states as Azerbaijan, Turkmenistan and Kazakhstan, after gained their independence, have prioritized assessing the hydrocarbon reserves of the region in line with their governance policies and have started to include external partners in their exploration and development study. In order to develop the long known hydrocarbon assets of the region, the exploration efforts carried out have enabled the discovery of new fields especially in the Azerbaijan sector of the southern Caspian region. In addition, hydrocarbons discovered in the onshore areas of both Kazakhstan and Turkmenistan have made the southern Caspian region the world's major hydrocarbon province. The tectonic evolution and petroleum systems of the hydrocarbon-bearing basins called as the North Caspian, Middle Caspian and South Caspian basins in the Caspian Sea region, differ in terms of both essential elements and processes. The most important differences of the South Caspian Basin are rapid deposition of more than twenty-five km thickness sediment fill resulting from an avalanche type sedimentation and the presence of the young Tertiary hydrocarbon source rocks and reservoirs. Therefore, generation-migration, accumulation and trapping processes of the South Caspian Basin petroleum system are still continuing.

Competitiveness of shallow water hydrocarbon development projects in Mexico after 2015 actualization of fiscal reforms: Economic benchmark of new production sharing agreement versus typical U.S. federal lease terms

Development of Mexican hydrocarbon reservoirs by foreign operators has become possible under Mexico's new Hydrocarbon Law, effective as per January 2015. Our study compares the economic returns of shallow water fields in the Gulf of Mexico applying the royalty and taxes due under the fiscal regimes of the U.S. and Mexico. The net present value (NPV) of the base case scenario is US$1.4 billion, assuming standard development and production cost (opex, capex), 10% discount rate accounting for the cost of capital and revenues computed using a reference oil price of $75/bbl. The impact on NPV of oil price volatility is accounted for in a sensitivity analysis. The split of the NPV of shallow water hydrocarbon assets between the two contractual parties, contractor and government, in Mexico and the U.S. is hugely different. Our base case shows that for similar field assets, Mexico's production sharing agreement allocates about $1,150 million to the government and $191 million to the contractor, while under U.S. license conditions the government take is about $700 million and contractor take is $553 million. The current production sharing agreement leaves some marginal shallow water fields in Mexico undeveloped for reasons detailed and quantified in our study.

Generalized field-development optimization with well-control zonation

Of concern in the development of oil fields is the problem of determining the optimal locations of wells and the optimal controls to place on the wells. Extraction of hydrocarbon resources from petroleum reservoirs in a cost-effective manner requires that the producers and injectors be placed at optimal locations and that optimal controls be imposed on the wells. While the optimization of well locations and well controls plays an important role in ensuring that the net present value of the project is maximized, optimization of other factors such as well type and number of wells also plays important roles in increasing the profitability of investments. Until very recently, improving the net worth of hydrocarbon assets has been focused primarily on optimizing the well locations or well controls, mostly manually. In recent times, automatic optimization using either gradient-based algorithms or stochastic (global) optimization algorithms has become increasingly popular. A well-control zonation (WCZ) approach to estimating optimal well locations, well rates, well type, and well number is proposed. Our approach uses a set of well coordinates and a set of well-control variables as the optimization parameters. However, one of the well-control variables has its search range extended to cover three parts, one part denoting the region where the well is an injector, a second part denoting the region where there is no well, and a third part denoting the region where the well is a producer. By this, the optimization algorithm is able to match every member in the set of well coordinates to three possibilities within the search space of well controls: an injector, a no-well situation, or a producer. The optimization was performed using differential evolution, and two sample applications were presented to show the effectiveness of the method. Results obtained show that the method is able to reduce the number of optimization variables needed and also to identify simultaneously, optimal well locations, optimal well controls, optimal well type, and the optimum number of wells. Also, comparison of results with the mixed integer nonlinear linear programming (MINLP) approach shows that the WCZ approach mostly outperformed the MINLP approach.

Source and Fate of Hydraulic Fracturing Water in the Barnett Shale: A Historical Perspective

Considerable controversy continues about water availability for and potential impacts of hydraulic fracturing (HF) of hydrocarbon assets on water resources. Our objective was to quantify HF water volume in terms of source, reuse, and disposal, using the Barnett Shale in Texas as a case study. Data were obtained from commercial and state databases, river authorities, groundwater conservation districts, and operators. Cumulative water use from ∼ 18,000 (mostly horizontal) wells since 1981 through 2012 totaled ∼ 170,000 AF (210 Mm(3)); ∼ 26 000 AF (32 Mm(3)) in 2011, representing 32% of Texas HF water use and ∼ 0.2% of 2011 state water consumption. Increase in water use per well by 60% (from 3 to 5 Mgal/well; 0.011-0.019 Mm(3)) since the mid-2000s reflects the near-doubling of horizontal-well lengths (2000-3800 ft), offset by a reduction in water-use intensity by 40% (2000-1200 gal/ft; 2.5-1.5 m(3)/m). Water sources include fresh surface water and groundwater in approximately equal amounts. Produced water amount is inversely related to gas production, exceeds HF water volume, and is mostly disposed in injection wells. Understanding the historical evolution of water use in the longest-producing shale play is invaluable for assessing its water footprint for energy production.

On structuring offshore hydrocarbon production sharing contracts: Lebanon's case

Interest in the Lebanese offshore hydrocarbon potentials has recently increased, especially after the discoveries in neighbouring countries that share the same geological offshore basin with Lebanon. In this article, we present a framework for structuring and analysing offshore hydrocarbon contracts. Our objective is to assist governments in formulating and managing the contracting process for hydrocarbon assets. The proposed framework is based on a benchmark study (ie database) of offshore production sharing contracts (PSCs). Contract profiling is then performed using three factors: political and economic risk, reserves status and water depth. Based on this database and on contract profiling, we propose plausible ranges for the parameters of potential PSCs; particularly, for Lebanon. We also utilise a simple ‘take’ model for PSCs to perform sensitivity analysis in order to identify critical contract parameters that have the highest effect on the government share. Additionally, our research statistically tests the significance of the three contract profiling factors on the PSC parameters.

Multiagent Systems Provide Support for Asset-Management Workflow Automation

This article, written by Editorial Manager Adam Wilson, contains highlights of paper SPE 150285, ’Decision Support and Workflow Automation for the Development and Management of Hydrocarbon Assets Using Multiagent Systems,’ by Amr S. El-Bakry, SPE, and Michael C. Romer, SPE, ExxonMobil Production Company; Peng Xu, Anantha Sundaram, and Adam K. Usadi, ExxonMobil Research and Engineering; H. Lane Morehead, SPE, ExxonMobil Upstream Research; and Mark L. Crawford, SPE, Bryce A. Holloway, and Charles A. Knight, ExxonMobil Information Technology, prepared for the 2012 SPE Intelligent Energy International, Utrecht, The Netherlands, 27-29 March. The paper has not been peer reviewed. Asset-management workflow automation poses challenges because these workflows are multidisciplinary, cross functional, and expertise intensive. Advancements in the fields of artificial intelligence, software engineering, and decision sciences have led to the development of multiagent systems (MASs). Each agent functions as an entity of a distributed computing system, performing a broad range of tasks that may include advanced analytics, data-quality checks, and oversight of other agents. Although agents may have competing priorities, they can convey information to one another to broker a decision. Introduction To improve the efficiency and effectiveness of asset management, it is essential to develop an integrated, flexible, and sustainable information-technology system that addresses these challenges. Such a system should integrate heterogeneous, distributed data sources and computer models (e.g., analytical models). It must process data automatically, converting them to high-level information understandable by people. It must be capable of developing asset- management plans, monitoring the execution of those plans, and adjusting them as necessary. Such a system should adhere to best-practice workflows and yet adapt to novel situations, allowing for easy customization to address evolving asset needs. The MAS technology and design approach can satisfy these requirements in a scalable, flexible, and sustainable way. MASs are composed of multiple interacting intelligent software agents, each of which is a computer entity that is capable of autonomous action within its environment to meet its objectives. Why MAS? An intelligent agent is an autonomous, goal-driven, problem-solving computational entity capable of effective operation in dynamic and open environments. It is a natural extension of modern software-design and -development best practices. Fig. 1a shows a schematic of an intelligent agent. Fig. 1b illustrates an agent using two methods to plan its actions. For simple scenarios, an agent acts in a reactive mode; it directly maps the state of the environment to an action. For more-complex scenarios, an agent operates in a deliberative mode; it uses more-sophisticated planning algorithms to identify a sequence of actions to achieve its goals.

Crossing the Technology Chasm: Permanent Downhole Monitoring

Editor’s note: This is the third and final installment of a multipart series examining key upstream technology uptake challenges in the oil and gas industry, and the reasons for the lack of accelerated acceptance of viable technologies needed to exploit increasingly challenging drilling and production environments. Similar to the managed pressure drilling (MPD) article published in the February JPT and the seismic while drilling (SWD) article in March, a permanent downhole monitoring (PDM) survey was conducted among SPE readership around the world. In total, about 1,500 SPE members responded to the survey. The majority of the respondents were operators (64%) and technology providers (13%). Unlike the previous two technologies analyzed, PDM generally has a higher level of acceptance among operators because it has been on the market for a longer time, and because significant reliability and performance improvements have occurred over the past several years. A key question in the survey was: “What are the main value propositions you see for permanent downhole monitoring?” As shown in Fig. 1, the most important value propositions were: 1) optimizing production through continuous information, 2) avoiding the necessity to shut in the well to obtain pressure ratings, and 3) emerging distributed temperature capabilities that add further value in understanding and optimizing production. There was general agreement among both operators and technology providers on the importance of these benefits. The relevance of these value propositions was stated by Shahab Mohaghegh, president of Intelligent Solutions: “The thought of being able to know what is going on in the well and in the reservoir in real time is very exciting. You imagine sitting in your office thousands of miles away from the field and being able to decide what needs to be done and then being able to see the consequences of your decision in near real time.” A similar view was expressed by Garrett Skaggs, monitoring product champion at Schlumberger. “The value of permanent downhole monitoring systems stems from the ability to provide continuous, reliable well and reservoir performance information without the need for intervention,” he said. “These measurements enable operators to manage decisions regarding hydrocarbon assets including production optimization, problem identification and diagnosis, updating reservoir models, and field development planning.” The growing importance of fiber optic technology and distributed temperature sensing was also raised by a number of operators. Significant improvements in these systems over the past few years have led to an increased acceptance of this downhole technology. In the view of Glynn McColpin, director of reservoir monitoring at Pinnacle (a Halliburton service): “I think we are actually seeing the next wave with fiber optic sensing. Electronics can only get you to a certain temperature, then you start worrying about longevity and failures. You start looking at the fiber optic solutions coming out—we can go into steam wells up to 350°C with just glass and the glass itself is a sensor.”

Technology Focus: Tight Reservoirs (October 2010)

Technology Focus Shale-gas reservoirs are becoming an increasingly significant percentage of the global tight-reservoir landscape. Three questions reflect this increasing dominance but are applicable overall to tight formations. Is the long multistage-fractured horizontal well into which millions of gallons of water are pumped downhole with only a third of the contacted reservoir propped open the most efficient way to produce the reservoir? Is the long multistage-fractured horizontal well the endgame solution to Master’s Resource Triangle? If the equations set forth by Darcy and Young/Laplace are valid, does contacting a large amount of the formation with only water constitute stimulation of the reservoir? Capillary pressure is significant in tight reservoirs. Stimulation-fluid invasion into smaller pore diameters and invasion of proppant-free stimulation fluid into both induced fractures and dilated natural fractures will have an effect. Production-decline rates and long-term health of wells (improved fluid flow or degree of formation damage) in tight reservoirs will depend on how capillary forces are managed in the reservoir. Log-normal large volumes of hydrocarbon found in tight reservoirs are difficult to develop because of constrained drainage areas, complicated petrophysics, lithology, and formation heterogeneity. These difficulties, complexities, and heterogeneities dictate planning of drilling, completion, and stimulation specific to the well in question. They also dictate continued advances in knowledge and technology if the majority of the hydrocarbon asset is to be produced effectively. Early production levels will be dependent on the length of propped fracture from the wellbore that has actually cleaned up and this contributing to hydro-carbon flow. Our industry needs to make advances in: real-time measurement; post-fracture monitoring with production analysis; identifying sweet spots, then placing perforations to create complex conductive fractures; innovative proppants and proppant-placement techniques in primary and complex fracture geometries; fluid recovery; formation-damage control and permeability enhancement; proppant transport with less-damaging stimulation fluids; and environmentally responsible drilling, completion, and production services. Tight Reservoirs additional reading available at OnePetro: www.onepetro.org SPE 128191 • “Selecting Drilling Technologies and Methods for Tight Gas Sand Reservoirs,” by Pilisi, N., SPE, Blade Energy Partners, et al. SPE 131778 • “Using Microseisms to Monitor Hydraulic Fractures in the Bakken Formation of North Dakota,” by Gary S. Forrest, Schlumberger, et al. SPE 130043 • “Fracturing Design Aimed at Enhancing Fracture Complexity,” by M.Y. Soliman, Halliburton, et al.

Hydrodynamic considerations for carbon storage design in actively producing petroleum provinces: An example from the Gippsland Basin, Australia

The Australian offshore Gippsland Basin has been investigated by the CO2CRC for its potential to store large volumes of CO 2 from new coal-fired power developments in the Latrobe Valley (Gibson-Poole et al., 2006). The Gippsland Basin has been producing hydrocarbons since the 1960s and the depletion and decommissioning of some of the major oil fields is likely to coincide with the need for storage of anticipated CO 2 emissions of up to 50 million tonnes annually for a 40 year injection period (Gibson-Poole et al., 2006). This will necessitate several individual storage sites to be used both sequentially and simultaneously, but timed such that existing hydrocarbon assets will not be compromised. Potential injection targets lie within the interbedded sandstones of the Upper Latrobe Group, regionally sealed by the Lakes Entrance Formation (Gibson-Poole, et al., 2006). A hydrodynamic evaluation of the Upper Latrobe Aquifer System (the Latrobe Group) mapped the hydraulic head distribution of the virgin formation water flow system and the impact on that system of the extraction of large volumes of gas and oil (Hatton et al., 2004; Underschultz and Johnson, 2005). They determined that offshore oil and gas production have resulted in significant, although short-term (tens to hundreds of years) alteration of the formation water flow system. This paper outlines a study investigating whether the local hydraulic gradients induced by pressure depletion in the vicinity of hydrocarbon production are sufficient to alter the buoyancy driven migration of injected CO 2. The methodology developed by Hubbert (1953) to determine the ability of geologic structures to hold hydrocarbons under varying hydrodynamic conditions was applied to CO 2 storage. An average density of injected CO 2 calculated from in-situ pressure and temperature conditions in the Latrobe aquifer was applied to both virgin and production affected hydrogeological environments. The results suggest that the location of reservoir spill points and the migration direction of CO 2 in the Latrobe aquifer would change continually due to the transient nature of the production impact on the formation water flow system. Therefore, it is not sufficient to calculate a static volume available for CO 2 storage within structural closures. The production lifetime of and the potential pressure interference between petroleum fields has to be taken into account when selecting sites for CO 2 geological storage.

Technology Focus: Well Testing (February 2009)

Technology Focus Many of us, at one time or another in our careers, have encountered industry colleagues or team members convinced of the need to gather information, sometimes at any cost. In contrast, just as many struggle with advocating even the most rudimentary data gathering to decision makers within their company. A common problem, particularly in small companies, can be a tendency to make quick decisions without considering possible effects by relying on past experience and judgment to expedite decision making for new problems. Planning can seem bureaucratic and unnecessary, particularly to less-experienced or nontechnical professionals. However, when objectives are not established and deliverables are not determined before making the final decision, the result can be a large invoice and information or service that is essentially useless. Modern software, sometimes with less effort than my children put into mastering the latest "Xbox 360" release, will transform any kind of input data into an impressive array of results that can provide compelling justification for a completely wrong conclusion. I am picturing trainloads of investors passing through early oil fields where a strong pump and full tank battery could provide an impressive "gusher" timed by the promoter for just the right moment! And even a cursory look at input and assumptions going into some of our modern analysis can keep us from drawing wrong conclusions. Along with colorful or animated results, the most useful and relevant analysis in our industry will always invest the necessary time to confirm quality of the input data and verify the purpose or application of the results. The papers highlighted on the following pages provide good examples of how unmet needs can provide insight into better analysis methods. New tools result from the need to acquire important information that would otherwise be uneconomic. Thorough engineers and technicians will be interested in the accuracy of their analysis as it relates to the quality of the input data. Solid analysis over time can uncover further insight into the performance of a hydrocarbon asset. I hope that you will find the selected papers of interest and that they will provide stimulation for new approaches in your well-testing and surveillance activities. Well Testing additional reading available at the SPE eLibrary: www.spe.org SPE 116744 • "Equivalent Skin Factors for Nonuniformly Damaged Horizontal and Multilateral Wells" by Turhan Yildiz, SPE, Colorado School of Mines SPE 118940 • "Evaluation of Skin Factor From Single-Rate Gas-Well Test" by K. Aminian, West Virginia University, et al. Additional reading available at OnePetro: www.onepetro.org OTC 19140 • "Oilwell Transient Testing by Injection of Miscible Liquid" by J.J. Voelker, SPE, Chevron

Site characterisation of a basin-scale CO2 geological storage system: Gippsland Basin, southeast Australia

Geological storage of CO2 in the offshore Gippsland Basin, Australia, is being investigated by the Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC) as a possible method for storing the very large volumes of CO2 emissions from the nearby Latrobe Valley area. A storage capacity of about 50 million tonnes of CO2 per annum for a 40-year injection period is required, which will necessitate several individual storage sites to be used both sequentially and simultaneously, but timed such that existing hydrocarbon assets will not be compromised. Detailed characterisation focussed on the Kingfish Field area as the first site to be potentially used, in the anticipation that this oil field will be depleted within the period 2015–2025. The potential injection targets are the interbedded sandstones of the Paleocene-Eocene upper Latrobe Group, regionally sealed by the Lakes Entrance Formation. The research identified several features to the offshore Gippsland Basin that make it particularly favourable for CO2 storage. These include: a complex stratigraphic architecture that provides baffles which slow vertical migration and increase residual gas trapping and dissolution; non-reactive reservoir units that have high injectivity; a thin, suitably reactive, lower permeability marginal reservoir just below the regional seal providing mineral trapping; several depleted oil fields that provide storage capacity coupled with a transient production-induced flow regime that enhances containment; and long migration pathways beneath a competent regional seal. This study has shown that the Gippsland Basin has sufficient capacity to store very large volumes of CO2. It may provide a solution to the problem of substantially reducing greenhouse gas emissions from future coal developments in the Latrobe Valley.