The high-profile blowout at Macondo well in the US Gulf of Mexico, brought the challenges and the risks of drilling into high-pressure, high-temperature (HPHT) fields increasingly into focus. Technology, HSE, new standards, such as new API procedures, and educating the crew seem to be vital in developing HPHT resources. High-pressure high-temperature fields broadly exist in Gulf of Mexico, North Sea, South East Asia, Africa, China and Middle East. Almost a quarter of HPHT operations worldwide is expected to happen in American continent and the majority of that solely in North America. Oil major companies have identified key challenges in HPHT development and production, and service providers have offered insights regarding current or planned technologies to meet these challenges. Drilling into some shale plays such as Haynesville or deep formations and producing oil and gas at HPHT condition, have been crucially challenging. Therefore, companies are compelled to meet or exceed a vast array of environmental, health and safety standards.
This paper, as a simplified summary of the current status of HPHT global market, clarifies the existing technological gaps in the field of HPHT drilling, cementing and completion. It also contains the necessary knowledge that every engineer or geoscientist might need to know about high pressure high temperature wells. This study, not only reviews the reports from the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) and important case studies of HPHT operations around the globe but also compiles the technical solutions to better maneuver in the HPHT market. Finally, the HPHT related priorities of National Energy Technology Laboratories (NETL), operated by the US Department of Energy (DOE), and DeepStar, as a strong mix of large and mid-size operators are investigated.
The high decline rate observed in over pressured shale has attracted the attention of the industry, and better well management procedures for long term productivity improvement are still evolving. Operators are recognizing some benefit in controlled rate (controlled drawdown) production as one way of improving well performance for the wells in over pressured stress sensitive formations.
During uncontrolled rate production because of high drawdown, the permeability in stress sensitive shales decays faster because of increased stress. Often high initial gas rate is accompanied by high decline rate as the permeability reduction takes effect. In addition, proppant could also be produced back, crushed or embedded in the formation. However, controlled rate production minimizes the rate decline, albeit at reduced initial gas rate. Modelers resort to using different stress permeability decay coefficients for these two production strategies. Higher values are assigned to uncontrolled rate production to produce lower EUR. This approach, although convenient, requires different permeability versus stress tables depending on the production strategy.
Porosity and pore volume reduction in shales could be as high as 20 percent due to changes in net stress. The pore volume reduction provides in situ energy for gas recovery. The increased rate of permeability decay due to changing in situ stresses reduces the effectiveness of pressure support from pore volume reduction as fractures close under stress.. Controlled rate production strategy slows down permeability decay rate and this enables better use of pore volume energy. The pore volume consideration could provide additional gain to EUR for controlled rate.
Our analytical simulation model couples geomechanics permeability and porosity stress coefficients and evaluates well performance under moderate and low net stress sensitivity. Haynesville and Marcellus shales were evaluated. The importance of pore volume stress effect from the stand point of well performance evaluation and reservoir characterization is assessed.
This paper presents a methodology for connecting geology, hydraulic fracturing, economics, environment and the global natural gas endowment in conventional, tight, shale and coalbed methane (CBM) reservoirs. The volumetric estimates are generated by a variable shape distribution model (VSD). The VSD has been shown in the past to be useful for the evaluation of conventional and tight gas reservoirs. However, this is the first paper in which the method is used to also include shale gas and CBM formations.. Results indicate a total gas endowment of 70000 tcf, split between 15000 tcf in conventional reservoirs, 15000 tcf in tight gas, 30000 tcf in shale gas and 10000 tcf in CBM reservoirs. Thus, natural gas formations have potential to provide a significant contribution to global energy demand estimated at approximately 790 quads by 2035.
A common thread between unconventional formations is that nearly all of them must be hydraulically fractured to attain commercial production. A significant volume of data indicates that the probabilities of hydraulic fracturing (fracking) fluids and/or methane contaminating ground water through the hydraulically-created fractures are very low. Since fracking has also raised questions about the economic viability of producing unconventional gas in some parts of the world, supply cost curves are estimated in this paper for the global gas portfolio. The curves show that, in some cases, the costs of producing gas from unconventional reservoirs are comparable to those of conventional gas.
The conclusion is that there is enough natural gas to supply the energy market for nearly 400 years at current rates of consumption and 110 years with a growth rate in production of 2% per year. With appropriate regulation, this may be done safely, commercially, and in a manner that is more benign to the environment as compared with other fossil fuels.
Over the last several years, horizontal drilling and multi-stage hydraulic fracturing have become the norm across the industry and proved crucial for economic production of natural gas from unconventional shale gas and ultra tight sandstone reservoirs, also referred to as nano-Darcy reservoirs.
Following the success of the Barnett shale, horizontal drilling and multi-stage hydraulic fracturing has spread across North America with new emerging shale gas plays such as the Eagle Ford, Woodford, Haynesville, Marcellus, Utica, Horn River
changing the industry's landscaping. In the current economic environment of high drilling and completion costs, coupled with lower commodity prices, the economic success of shale gas developments has become reservoir specific.
Evaluation of well's initial performance in a particular field and especially the ability to accurately predict the long term production behavior and EUR is critical to the efficient deployment of large capital investments. Field analogies making use
of arbitrary "type curves?? can have a significant negative impact on the project's bottom line.
With the growing number of multi-stage horizontal wells producing from shale gas reservoirs, many "unconventional?? production analysis techniques have been developed based on new concepts such as stimulated reservoir volume (SRV),
fracture contact area (FCA), or sophisticated mathematical relationships (power law decline curves, linear flow type curves, to name a few). These sophisticated engineering processes are well documented in the literature and have been presented at
numerous industry work shops and conferences. However, for the majority of these techniques there is one common reoccurring theme: performance evaluation of shale gas production cannot be analyzed using conventional methods (e.g.
This paper will demonstrate how the conventional approach of reservoir characterization, well performance evaluation and forecasting, can be implemented for all unconventional gas reservoirs, using traditional well testing and production data
analysis techniques. We will present one simple analytical model based on the solution of the pseudo steady state equation and will introduce the concept of a shale gas normalized production plot. In our view, the shale gas normalized production
plot is one type curve generally applicable to any shale gas reservoir.
Finally, pre-frac in-situ testing techniques will be reviewed and special consideration will be given to the perforation inflow diagnostic (PID) testing. We will emphasize the importance of specific reservoir parameters (pore pressure and in-situ shale
matrix permeability) and show their impact on drilling and completion strategy and design. Field case examples including well test results and production data from wells completed in several shale gas reservoirs are presented.
Neber, Alexander (Schlumberger) | Cox, Stephanie (Schlumberger) | Levy, Tom (Schlumberger) | Schenk, Oliver (Schlumberger) | Tessen, Nicky (Schlumberger) | Wygrala, Bjorn (Schlumberger) | Bryant, Ian David (Schlumberger)
New tools are now available to provide a rigorous and systematic play-based exploration approach to the evaluation of unconventional resources. Coupled with petroleum system modeling, this methodology offers an efficient and effective approach to identify "sweet spots?? early in the life of resource plays. Petroleum system modeling can be applied to predict the type and quantity of hydrocarbon in shale formations, as well as the proportion of adsorbed gas and geomechanical properties that are important for hydraulic fracture stimulation of shale reservoirs. Maps of these properties are then converted to chance-of-success maps for hydrocarbon generation, retention, and pore volume that can be integrated with nongeological factors, such as access and drilling depth required to reach target reservoirs. These play-based maps are expressed in probability units, so simple map multiplication provides a map of the play's overall chance of success, delineating the sweet spots. A similar methodology is applicable to evaluation of coalbed methane resources.
In this paper, we illustrate this methodology using examples from shale oil and gas shale plays in North America. These include data-rich plays from the North Slope of Alaska and data-poor plays from the northeastern and southern regions of the United States, which are more representative of many Asia-Pacific basins. We show how predictions from petroleum system modeling based on sparse data provide a good match with results of subsequent development drilling and production.
Petroleum system-based assessment of resources in place, combined with an assessment of overall play risk, enables companies to make decisions on acquisition of acreage early in the life of unconventional resource plays based on the probability of them containing economically viable resources.
Thermal maturity is an important parameter for commercial gas production from gas shale reservoirs if the shale has considerable organic content. There is a common idea that gas shale formations with higher potential for gas production are at higher thermal maturity status. Therefore estimating this parameter is very important for gas shale evaluation. The present study proposes an index for determining thermal maturity of the gas shale layers using the conventional well log data. To approach this objective, different conventional well logs were studied and neutron porosity, density and volumetric photoelectric adsorption were selected as the most proper inputs for defining a log derived maturity index (LMI). LMI considers the effects of thermal maturity on the mentioned well logs and applies these effects for modelling thermal maturity changes. The proposed methodology has been applied to estimate thermal maturity for Kockatea Shale and Carynginia Formation of the Northern Perth Basin, Western Australia. A total number of ninety eight geochemical data points from seven wells were used for calibrating with well log data. Although there are some limitations for LMI but generally it can give a good in-situ estimation of thermal maturity.
Thermal maturity and total organic carbon (TOC) are very important geochemical factors for evaluation of the gas shale reservoirs. There is a common hypothesis that gas shale layers with the higher potential for gas production (i.e. sweet spots) are located at the higher thermal maturity. Thermal maturity is an indicator for determining maximum temperature that a formation reached during different stages of hydrocarbon generation.
The Cascade and Chinook Project is located in the Walker Ridge area in the Gulf of Mexico (GOM), 250 miles south of New Orleans in depths between 8,200 and 8,900 ft. The oil-producing reservoir is in the Lower Tertiary Wilcox formation, with a gross sand thickness of 1,200 ft. The reservoir midpoint is at an average depth of 25,600 ft true vertical depth subsea (TVDss), with a bottomhole pressure of 19,500 psi and a bottomhole temperature of 260°F. The reservoir comprises vertically stacked thin beds of sand and fine-grained-siltstone intervals with effectively no vertical permeability. Additional information on this project can be found in Moraes et al. (2010).
Multiple limitations were considered during the initial design phase of the frac-pack program. The fracs were designed taking into account the use of a single-trip multizone (STMZ) sand-control system. Some of these design challenges are briefly discussed by Cunha et al. (2009). Although this system was not crucial in the overall implementation of the frac program, it added additional complexity from an operational standpoint because of a continuous, multistage frac operation. Some of the operational limitations included service-tool-erosion limitations because of maximum pump rates and proppant volumes, overall frac-vessel capacity, boat-to-boat fluid transfers, and crew fatigue. The geological complexities of the reservoir were another major challenge in completing this very thick interval. Perforation intervals had to be placed to avoid a fault (and thus a potential early screenout), avoid a water contact, and comply with tool-spacing limitations, and still had to maximize contact with net pay.
This paper addresses the approach taken to develop a fracture-stimulation program for the Lower Tertiary formation in the Cascade and Chinook Project. Some of the major questions addressed during this process include the following: How many fracture treatments are needed? What is the optimum fracture geometry? What is the desired conductivity? How to effectively position the perforation intervals? What is the desired pump rate, and is a high-density fluid needed to fracture this deep, high-pressure formation? The approach, the answers, and the treatment are discussed along with responses to additional questions that arose during the actual fracturing operations.
Along with the Lower Tertiary in the GOM, the industry faces similar challenges around the world. These include reservoirs with potentially large reserves but much lower permeability (caused by depth and in-situ stresses) where fracturing is required for both stimulation and potential-formation-collapse sand control. Careful planning is necessary to avoid costly learning curves in these environments.
Many shale gas reservoirs have been previously thought of as source rocks, but the industry now finds these source rocks still contain large volumes of natural gas and liquids that can be produced using horizontal drilling and hydraulic fracturing. However, one of the most uncertain aspects of shale gas development is our ability to accurately forecast gas resources and shale gas development economics. The uncertainty of the problem begs for a probabilistic solution.
The objective of our work was to develop the data sets, methodology and tools to determine values of original gas in place (OGIP), technically recoverable resources (TRR), recovery factor (RF) and economic viability in highly uncertain and risky shale gas reservoirs. Existing approaches for determining values of TRR, such as the use of decline curves or even volumetric analyses, may not be reliable during early time because there may not be enough production history for decline curves to work well or the uncertainty in the reservoir properties may be too large for volumetric analyses to be useful.
To achieve our research objective, we developed a computer program, Unconventional Gas Resource Assessment System (UGRAS). In the program, we integrated Monte Carlo technique with an analytical reservoir simulator to estimate the original volume in place, predict production performance and estimate the fraction of TRR that are economically recoverable resources (ERR) for a variety of economic situations. We applied UGRAS to dry gas wells in the Barnett Shale and the Eagle Ford shale to determine the probabilistic distribution of their resource potential and economic viability. Based on our assumptions, the Eagle Ford shale in the dry gas portion of the play has more technically recoverable resources than the Barnett shale. However, the Eagle Ford shale is currently not as profitable as the Barnett shale because of the higher drilling costs in the Eagle Ford dry gas window.
We anticipate that the tools and methodologies developed in this work will be applicable to any shale gas reservoirs that have sufficient data available. These tools should ultimately be able to allow determination of technically and economically recoverable resources from shale gas reservoirs globally.