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The definition of a tight gas reservoir is that the reservoir does not produce at commercial gas flow rates, or recover commercial volumes of natural gas, unless a hydraulic-fracture treatment is properly designed and pumped. As such, the entire drilling and completion procedures should focus on making sure the optimum fracture treatment can be designed and pumped in the field. When drilling a tight gas well, the most important aspect of the drilling operation is to drill a gauge hole. Many times this means the well should be drilled at a balanced mud weight or slightly overbalanced. In other cases, air drilling or underbalanced drilling works best, as long as the hole remains in gauge.
Abdelaziz, Sherif (Halliburton) | Leem, Junghun (Halliburton) | Praptono, Andri Setyanto (Halliburton) | Shankar, Pranay (Cairn India Limited) | Mund, Bineet (Cairn India Limited) | Gupta, Abhishek Kumar (Cairn India Limited) | Goyal, Rajat (Cairn India Limited) | Sidharth, Punj (Cairn India Limited)
Abstract A tight-gas reservoir commonly refers to a low-permeability reservoir that mostly produces natural gas. Irrespective of the reservoir rock type (e.g. sandstone, shales, coal seams or volcanics), they all have one thing in common—these reservoirs cannot be produced at economic rates without an effective hydraulic fracturing treatment. In conventional reservoirs, rock flow capacity is usually sufficient to allow for hydrocarbons flow; therefore, hydraulic fracturing is broadly considered as a remedial technique to improve the productivity of suboptimal producing wells. In this study, fracturing was not originally considered in the primary drilling and completion planning phases, which in many cases limited the effectiveness of fracturing treatments because of challenges resulting from the well architecture, trajectory, azimuthal orientation with respect to dominant stress regimes, and other factors. As the importance of unconventional resources for hydrocarbon production has increased dramatically during the past decade and more attention and efforts are focused globally to explore these reserves, the demand for hydraulic fracturing techniques to prove the economic profitability of these resources has in turn tremendously increased. This has created a paradigm shift, as operators are beginning to recognize that they need to drill and complete wells for hydraulic fracturing to maximize the return on their assets. Therefore, hydraulic fracturing has gained an advanced position in the planning phase of unconventional assets. Volcanic formations are one of the rarer rock types with the potential for accumulations of hydrocarbons that can produce economically. This rarity has resulted in a lack of understanding across the industry on the nature of these reservoirs and how to successfully turn them into lucrative assets. Because of the tight nature of these formations, optimal hydraulic fracturing strategies are intrinsically necessary for economic production. Without a thorough and integrated understanding of the petrophysical and geomechanical properties of these formations, it will be difficult to interpret the fracture growth behavior and its inherent effect on fracture flow capacity in the production phase.
Nadezhdin, Sergey (Schlumberger) | El Gihani, Mahmoud (Schlumberger) | Al Alqam, Amin (Schlumberger) | Briner, Andreas (PDO) | Harrasi, Othman (PDO) | El-Taha, Yasin (PDO) | Batmaz, Taner (Schlumberger)
Abstract Since 2012, Petroleum Development Oman (PDO) has attempted several hydraulic fracture monitoring (HFM) evaluations in deep, high-temperature, tight gas wells in the Amin Formation of the Fahud salt basin. The first successful job was executed in late 2014 for treatments placed in a horizontal wellbore. Following this job, in-depth HFM analyses were conducted that led to recommendations on well completion and fracturing treatment improvements. The purpose of the HFM trial in this challenging tight gas Amin reservoir of the Fahud salt basin was evaluating hydraulic fracture geometries, fracture propagation, and orientation. The horizontal well had been purposely drilled in the vicinity of an earlier completed vertical well to enable execution of the HFM job. Microseismic monitoring provided a direct measurement of the rock-failure coordinates and helped in gauging the effectiveness of the hydraulic fracture treatment placed in two clusters of the same fracturing stage. A large set of raw data representing 52,000 triggers was recorded and processed through different filtering methods including processing noise generated from gas flow in the monitoring well behind the casing. The evaluation suggested that the fractures have grown upward. It also revealed fracture length dimensions and stimulated reservoir volume along with the previously unmeasured fracture azimuthal orientation. The HFM job provided insight on how the hydraulic fractures propagate when two perforation clusters are placed in different stress zones, and if it is possible to place comparable hydraulic fractures in both. HFM results were coupled with geomechanics work and post-fracturing production logging to develop recommendations for future well completion improvements.
Abstract A large, strategically important unconventional (tight) gas project in the Sultanate of Oman advanced from the exploration stage with one discovery well to the pilot and development stages over 4 years. Project challenges in the first 2 years of exploration were poor initial success in both fracturing treatment placement and subsequent productivity and an ever-expanding scope of work in a demanding environment with limited resources. To address these challenges, the focus was shifted from routine delivery to an integrated approach and a strategy that included defined activity timelines, key performance indicators aligning with different stakeholders, and process reviews. Technology deployment and improved operations with allocated fracturing equipment spread gave flexibility to this new efficiency model. Integrated technology trials included cased and openhole completions; different well types; and several rock and core mechanical tests, such as reservoir coring, openhole stress testing, sonic measurements, and continuous unconfined compressive strength measurements. It also incorporated abrasive perforating, various fracturing treatment type designs, and advanced evaluation techniques such as microseismic monitoring, three-phase flow metering, tracers, and others. These technologies were implemented in a fast and efficient manner owing to strong collaboration between a dedicated Petroleum Development Oman (PDO) subsurface team and the service provider expertise. Personnel embedded in the exploration team greatly helped with linking to proper resources within the suppliers. An embedded engineer provided immediate technical and logistical support to the team. The improved process involved multiwell fracturing, a test campaign, and evaluation of individual zones. Finally, gaps and areas for improvement going forward were identified. Over the 4 years, with implementation of the new technology and strategy, the success rate of fracture placement and zonal evaluation increased from the low initial success of less than 50% to 100%; the improvement was particularly evident in the extremely tight lower intervals of the reservoir.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 170852, “Development of a Stranded Tight Gas Field in the UK Southern North Sea With Hydraulic Fracturing Within a Subsea Horizontal Well: A Case Study,” by Marc Langford, SPE, Douglas Westera, SPE, and Brian Holland, SPE, Centrica Energy, and Bogdan Bocaneala, SPE, and Mark Norris, SPE, Schlumberger, prepared for the 2014 SPE Annual Technical Conference and Exhibition, Amsterdam, 27–29 October. The paper has not been peer reviewed.
There are more than 100 accumulations in the southern North Sea that are flagged as stranded fields. One of these stranded tight gas fields, the Kew field, has been developed successfully with the use of a subsea well, horizontal drilling, and hydraulic fracturing. Because this was a subsea development well, all the hydraulic-fracturing operations had to be performed with the rig in place. The utmost efficiency of the operations was paramount; otherwise, the economics of the project would be affected negatively.
The Kew field is a gas field, with small volumes of associated condensate, located in Blocks 49/4a, 49/5a, 49/5b, and 49/4c of the UK continental shelf. It lies 120 km east of the English coast and 5 km west of the UK/Netherlands median line. The field location is pictured in Fig. 1. (For further geological and geophysical details of the Kew field, please see the complete paper.)
The planned Kew 49/04c-7Y subhorizontal development well was drilled along the crest of the Kew structure and is a sidetrack of the existing (suspended) Kew appraisal well 49/4c-7z.
The planned sidetrack 49/04c-7Y was initially intended to target the Lower Carboniferous units. To maximize reservoir contact, the well was initially planned to be completed with four to five hydraulic fractures, with a minimum of one per target unit. Because of the proximity to the gas/water contact, the decision was made to complete the well with a cased-and-cemented liner and plug-and-perforation technique for placement and isolation of the hydraulic fractures. Previous experiences with openhole uncemented multistage systems have positively affected the efficiency of hydraulic-fracturing execution in the North Sea. Also, previous experience of spalling and out-of-gauge hole was another driver toward a cemented system.
Abstract Natural gas production from unconventional gas reservoirs in North America rely on the technologies of horizontal drilling and multi-stage hydraulic fracturing. The cased and cemented completion technique, Plug-and-perf (P-n-P), has been utilized as a traditional completion in horizontal wells for many years. However, the openhole completion technique, Open Hole Sleeve Multi-stage System (OHMS), has gained favor in the past decade, because of its cost and time efficiencies. Production comparisons between these two completion methods remain a controversial subject, with ongoing debate regarding which method yields more gas production. Historical studies compare production indicators, typically from a limited set of sample wells. These historical studies indicate either insignificant differences between the two completion methods, or that OHMS systems significantly outperform P-n-P. However, these historical studies are limited in a number of ways. A computational fluid dynamics model (CFD) has been developed to compare P-n-P completions with OHMS for horizontal, multi-stage fractured wells. The numerical model uses a 6-inch borehole draining a tight gas reservoir (0.01 mD), under steady state flow with no formation damage. The P-n-P completion assumes 0.22 in., 180o phased perforations connecting to a planar fracture penetrating the height of the reservoir. The OHMS completion assumes sandface flow, and no orifice effect from the sleeve openings. Both completions assume the planar fracture intersects at the center of the reservoir model. The results of the CFD analyses compare the productivity index ratio (J/Jo) verses dimensionless fracture conductivity (Cfd) for each completion over a range of fracture conductivity (kfw) obtained from commercial proppant data. Parametric studies were performed varying propped fracture width, fracture half-length and vertical to horizontal permeability ratio (kv/kh), to investigate the effects of these parameters on the completion comparison. This paper presents the results of the numerical modeling and compares productivity index results to historical, production-based studies of the P-n-P and OHMS completions in horizontal, multi-stage fractured wells. This work verifies a slight production advantage in OHMS systems versus P-n-P completions used in horizontal wells today. The work is significant because few, if any, numerical models have been developed to study and compare performance of these completions.
Copyright 2013, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Middle East Unconventional Gas Conference and Exhibition held in Muscat, Oman, 28-30 January 2013. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is proh ibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Since the late 1990ies Petroleum Development Oman L.L.C. (PDO) is actively exploring for tight gas onshore in the North of the Sultanate of Oman.
Abstract In 2009 Petroleum Development Oman LLC (PDO) started an ambitious tight and deep gas exploration programme exploring for previously untapped reservoirs. The exploration strategy is focusing on both conventional tight gas plays as well as deep unconventional gas resources. These resources are typically in previously undrilled formations at great depths, with high temperatures and unknown pressure regimes, and uncertain fluid fill and composition. The unique geological properties of this type of reservoir require different strategies and technology deployment in order to make them viable and sustainable. With unique geomechanical, reservoir, and geological properties, some of the large gas-bearing prospects within the Fahud Basin in the Sultanate of Oman require innovative drilling and completion practices. A revised drilling and completion workflow, with specific technology deployment and operational flexibility, has been developed in order to account for such reservoir complexity. This workflow includes the incorporation of rock strength acquisition and stress state of the reservoir prior to completion, in order to identify targets for hydraulic fracturing and quantify hydraulic fracturing performance versus reservoir deliverability. The unparalled challenges encountered whilst exploring for these resources required resolving to new technologies from outside the region and adapting them to local conditions. This paper demonstrates the need of integrating various unconventional data sources to enhance the chance of successful reservoir characterization that leads to better understanding of presence of hydrocarbons and reservoir quality. It will also show that classical evaluation methods fail and will not lead to unambiguous interpretations. Recent experience has shown that several independent data sources need to be applied to confidently evaluate well results. The successful application of a technology plan covering aspects of geomechanics, well completions, perforation and formation breakdown, hydraulic fracture placement and treatment yielded positive results that will be of interest to other regional operators facing similar challenges.
Abstract The West Asset of Brunei Shell Petroleum (BSP) is an offshore-based oil & gas production asset with substantial volumes of non-associated gas from deep, low permeability reservoirs. The typical depths of these reservoirs are from ca. 9000 ft to 11000 ft tvdss having a permeability range of 0.1 - 10 mD and porosity range of 9% -13%. In the past, the completion type for the deep, tight gas reservoirs has been primarily cased-hole and perforated. The production rates has not been sustainable and was observed to decline faster than expected and ceased production, at reservoir pressures significantly higher than expected abandonment pressure. Investigation showed that these wells quit prematurely due to high skin, although the actual damage mechanism i.e. from fines migration, condensate banking, water banking or clay swelling, is still unknown. Production remediation via acid stimulation and through-tubing re-perforation did not achieve the desired results. Consequently, there is a demand for the West Asset to pursue different completion strategies primarily dedicated to develop deep, tight gas reservoirs. Hydraulic fracturing is one of the completion concepts proposed to test the reservoir producibility performance. Other than a failed "Skin-Frac" campaign attempt in the past, hydraulic fracturing technology has not been widely applied in BSP. With a lack of geomechanics data and fracturing experience, a number of challenges were confronted during well planning and completion design phase as well as during planning and execution of the hydraulic fracturing campaign. In the past two years, two wells have been hydraulically fractured by bull heading through 4-1/2" monobore completion via frac boat. Therefore, this case study documents the evolvement of completion and hydraulic fracturing strategies, emphasizing the importance of perforation selection, fluid selection and hydraulic fracture designs to the overall outcome of well performance. This paper also captures the operational challenges and learnings experienced throughout the campaign. This campaign has gathered valuable information on fracturing data and provided better understanding on future completion and fracturing approaches for new tight gas wells in the West Asset and similar assets in Brunei.
Tolman, Randy C. (ExxonMobil) | Simons, Jeff W. (ExxonMobil Production Co.) | Petrie, Dennis H. (ExxonMobil Upstream Research) | Nygaard, Kris J. (ExxonMobil Upstream Research) | Clingman, Scott (ExxonMobil Upstream Research) | Farah, Ali M. (ExxonMobil)
Abstract Progressively, the oil and gas industry is producing from unconventional reservoirs with low permeability in numerous small pay zones that require close well spacing and multiple stimulations in each well. To effectively produce from such reservoirs and reduce the surface footprint, ExxonMobil has drilled multiple wells from single pads, and new technologies have been developed to efficiently stimulate the multiple pay zones in each well. ExxonMobil has developed and licensed Multi-Zone Stimulation Technologies (MZST), which are designed to efficiently stimulate wells with multiple pays zones. The technologies have been applied in fracturing tight gas reservoirs with numerous lenticular sands in the Rocky Mountains. We have also developed a technology that enables the simultaneous stimulation of multiple wells on the same or different well pads, and while drilling additional wells. The benefits of this technology include reduced environmental impact, time saving, and improved production rates. Most importantly we have demonstrated that these simultaneous operations can be conducted in a safe and responsible manner to ensure the highest standards of operations integrity. This paper introduces the method and apparatus for this technology and discusses the results from several years of field applications, including the Piceance Basin. Some specific elements of the simultaneous operations safety plan will also be provided. Introduction Worldwide, substantial oil and gas resources are contained in low permeability formations. Many of these resources are characterized by thick intervals and/or multiple reservoir targets. In addition, matrix or fracture stimulation treatments are typically required to effectively and optimally produce these resources. However, the increased geologic and reservoir heterogeneities present in these resources can lead to substantial challenges in the stimulation treatment operations and effectiveness. Over the last several decades, industry has invested substantial research in attempts to develop new drilling and completion technologies for application in tight gas sand reservoirs. Various government and industry studies indicate a vast amount of tight gas resources exist within the United States alone, with similar resources located outside the U.S. Examples of such resources are found widely distributed in the western United States, and include the Green River, Piceance, Wind River and Uinta Basins.