At the present time, more than 9,000 offshore platforms are in service worldwide, operating in water depths ranging from 10 ft to greater than 5,000 ft. Topside payloads range from 5 to 50,000 tons, producing oil, gas, or both. A vast array of production systems is available today (see Figure 1). The concepts range from fixed platforms to subsea compliant and floating systems. In 1859, Col. Edwin Drake drilled and completed the first known oil well near a small town in Pennsylvania, U.S.A.
In-situ combustion is the oldest thermal recovery technique. It has been used for more than nine decades with many economically successful projects. In-situ combustion is regarded as a high-risk process by many, primarily because of the many failures of early field tests. Most of those failures came from the application of a good process to the wrong reservoirs or the poorest prospects. The objective of this page is to describe the potential of in-situ combustion as an economically viable oil recovery technique for a variety of reservoirs.
Cronkwright, David (University of Calgary) | Ghanizadeh, Amin (University of Calgary) | DeBuhr, Chris (University of Calgary) | Song, Chengyao (University of Calgary) | Deglint, Hanford (University of Calgary) | Clarkson, Chris (University of Calgary) | Ardakani, Omid (Geological Survey of Canada)
This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Denver, Colorado, USA, 22-24 July 2019. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not necessarily reflect any position of URTeC. Any reproduction, distribution, or storage of any part of this paper by anyone other than the author without the written consent of URTeC is prohibited. Abstract Fluid distribution and fluid-rock interactions within the nano-/macro-porous pore network of tight oil reservoirs will affect both primary and enhanced oil recovery (EOR) processes. Focusing on selected samples obtained from the liquids-rich reservoirs within the Montney Formation (Canada), the primary objective of this work is to evaluate the impact of mineralogical composition on micro-scale fluid distribution at different saturation states: 1) "partially-preserved" and 2) after a series of core-flooding experiments using reservoir fluids (oil, brine) under "in-situ" stress conditions. Small rock chips (cm-sized), sub-sampled from "partially-preserved" (using dry ice) core plugs, were cryogenically frozen and analyzed using an environmental field emission scanning electron microscope (E-FESEM) equipped with X-ray mapping capability (EDS).
Bryndzia, L. Taras (Shell International Exploration and Production) | Hows, Amie M. (Shell International Exploration and Production) | Day-Stirrat, Ruarri J. (Shell International Exploration and Production) | Nikitin, Anton (Shell International Exploration and Production) | Huvaz, Ozkan (Shell International Exploration and Production)
The Permian Delaware Basin (DB) is one of the most desirable regions for production of unconventional oil in the United States. While extended horizontal wells, stimulated with hydraulic fracturing, can recover economic volumes of oil in the DB, this production is often associated with large volumes of water. Relatively high water-oil ratios (WORs) can erode the value of producing wells. This of course begs the questions: where is the water coming from and why is so much being produced?
This study shows that the produced waters (PWs) are primarily in-situ Wolfcamp shale formation water and not water associated with hydraulic fracturing or well completions. This conclusion is based on the observation that the Wolfcamp shale formation water has an oxygen isotopic composition of ~6.5 ± 0.5 ‰ (SMOW) and a salinity of ~23 kppm. These oxygen isotopic data and salinities are consistent with illite-water equilibrium at peak burial conditions.
However, in some areas of the DB, PWs have much higher salinities (~50-125 kppm). The PWs also have a characteristic geochemical fingerprint of highly radiogenic 87/86Sr ratios of ~0.7085-0.7095. The source of this highly radiogenic strontium is believed to be the Salado salt in the overlying shallow Ochoan evaporites, with 87/86Sr of ~0.7090-0.7095. Dissolution of the Ochoan evaporites and salt is the likely source of high salinity brines in Guadalupian and Leonardian age sands and silts within the DB. These high salinity PWs are mixtures of Wolfcamp formation water and dissolved Ochoan evaporites and salt that infiltrated deep into the DB during uplift of the western edge of the DB. Uplift was closely related to the formation of the “Alvarado Ridge”, beginning at ~20 Ma, with peak uplift at ~7 to 4 Ma, creating conditions hydrologically favorable for ingress of the high salinity brines deep into the DB.
Due to the high illite content in the Wolfcamp shale, the shale-silt interface likely behaved as a clay membrane. Differences in salinity (up to ~100 kppm) between shales and sands/silts created gradients in ion and water activity (aw) across the interface. These gradients resulted in the diffusion of ions from high salinity sands/silt (low aw) into adjacent shales with high aw and low salinity. Where shales have not equilibrated with high salinity sands/silts, the water saturation (Sw) in the Wolfcamp shale would remain high and the resultant WOR would also be high. The ion diffusion model predicts co-current flow of oil and water out of the shale. This may explain why oil production in the DB produces so much water.
In the Dunvegan Kaybob South Pool, recent multistage fracked horizontal wells have revealed the presence of a light oil play enveloping a large legacy gas field, developed with vertical wells. The boundary between the oil and gas producing areas intersect structural contours a high angle within deltaic sandstones of the Cretaceous Dunvegan Formation. To address controls on this boundary, a multidisciplinary study of cores, core analysis data, well logs was completed and integrated with test and production data to identify controls on fluid production.
Legacy gas production is from relatively high permeability delta front sandstones, while oil dominated production occurs from lower permeability, fine grained pro-delta deposits. While wells within the legacy gas field produce very low volumes of oil, core fluid extractions reveal significant oil is also present within this portion of the reservoir, but is not mobile. The Dunvegan clearly demonstrates permeability as the main control on the anomalous fluid distributions, with several other tight sandstone plays showing similar relationships, although often more subtle, such as observed in the Cardium, Montney, etc.
The anomalous fluid distributions with higher gas saturations in higher permeability beds and higher oil saturation in lower reservoir quality beds contradict conventional capillary reservoir charge models. Thus, we propose late stage migration of predominantly gas related to the increase in gas generation post peak oil window due to increasing maturity of the kerogen during burial. These late generated gas fluids migrated from the deeper part of the basin preferentially within higher permeability strata and fractures, and displace the earlier emplaced oil resulting in reservoirs with high GOR. These counterintuitive observations with higher liquids production from lower reservoir quality, can significantly improve the play economics and allow better prediction of fluid distribution in many plays.
Although unconventional low permeability reservoirs form laterally continuous thick hydrocarbon accumulations, they often have variable liquid saturations vertically and laterally. While varying kerogen type and maturity are important controls. In several plays, fluid distribution shows a strong correlation with permeability, with higher gas saturations occurring in more permeable beds. The control of permeability on anomalous fluid distribution has been discussed for several clastic, low permeability unconventional light oil and liquid rich gas plays in the Western Canada Sedimentary Basin (e.g. Wood and Sanei 2016, Venieri and Pedersen 2017). In this study we present a study of a legacy gas pool producing from deltaic sandstone reservoirs of the late Cretaceous Dunvegan Formation (Figure 1). The pool is located within the deep basin of western Alberta, an area of pervasive hydrocarbon saturation charged by enveloping thermal mature organic rich mudstones and coals (Masters 1984). The Dunvegan Kaybob South Pool is comprised of a lowstand delta lobe of the southward prograding Dunvegan Delta (Bhattacharya 1993).
Objectives/Scope: The continuous drive by the E&P industry to deliver additional value and performance improvements in unconventional reservoirs has created the need for innovative advances in technology to meet evolving challenges. Jweda et al. (2017) and Liu et al. (2017) developed a novel time-lapse geochemistry technology calibrated to core extracted oils to cost effectively ascertain vertical drainage, which is among the most critical parameters used in determining optimal field development strategies. Aqueous geochemistry, well-established in academic and environmental investigations, is another technology that can be used in conjunction with time-lapse hydrocarbon geochemistry to evaluate drainage behavior, vertical connectivity between stacked wells and to ascertain the efficacy of different stimulation designs. Methods/Procedures/Process: More than 300 produced water samples from approximately 60 different Eagle Ford wells have been collected across ConocoPhillips’ Eagle Ford acreage. Sampling campaigns have included collecting several long-term time-series and baseline samples from individual wells across the field. The analytical program consists of a suite of total ion chemistry (cations and anions), salinity, alkalinity, and isotopic geochemistry (δ18O, δD, 87Sr/86Sr, δ11B). Results/Observations/Conclusions: Produced waters, contain a robust arsenal of geochemical signals that can be analyzed to understand the provenance(s) and change(s) in composition with time of these produced waters. A combination of interpretative and multivariate statistical tools were used to gain a deeper understanding of water-rock interactions and mixing/diffusion processes in the subsurface. Stimulation water was differentiated from in-situ formation water, and the evolution of that process was tracked over time. Time-series water analyses were also used to evaluate differences between completion designs, determine the vertical drainage and/or communication between wells, and ultimately understand the drained rock volume through time. Applications/Significance/Novelty: We clearly demonstrate that produced waters are mixtures of stimulation and formation water and that long-term geochemical signals from different layers within the Eagle Ford can be differentiated using aqueous geochemistry. Furthermore, we show that the formation waters vary vertically, coincident with hydrocarbon indicators (oil biomarkers and gas isotopes). To our knowledge, this is among the first published studies of aqueous geochemical behavior of produced waters in the Eagle Ford and the first to establish that intra-formational waters can be discerned, which is particularly novel and important for evaluating completion designs and strategies within a stacked development.
Fisher, Aaron (Tracker Resource Development) | O'Keefe, F. X. (Tracker Resource Development) | Niedz, Chris (Tracker Resource Development) | Wehner, Brian (Tracker Resource Development) | Kramer, Nick (Apex Petroleum Engineering) | Heuermann, Paul (Apex Petroleum Engineering) | Patrick, Scott (Fracture ID)
From 2010 to 2014 horizontal drilling activity in the Wolfcamp was focused in the southern Midland Basin, primarily within western Irion, northern Crockett, and southeastern Reagan counties. Well results were extremely variable due to a variety of reasons such as matrix quality, hydrocarbon saturation, faulting, influx of carbonate debris flows, operator, etc, and to this day remain variable. Filtering the well results by operator, vintage, completion style, and target formation helps to explain much of the variation, yet when the above variables were controlled for, large differences in productivity still exist across small distances.
Tracker began this project with approximately 42 square miles (mi2) of 3D seismic data, and during the course of the next five years licensed an additional 88 mi2 of 3D seismic data from offset operators. Tracker worked with APEX Petroleum Engineering (APEX, formerly SIGMA3) to construct a 3D reservoir model that utilized core, wells with full log suites, and ~130 mi2 of prestack time migrated seismic to delineate target zones. While the Wolfcamp is almost entirely hydrocarbon charged, these volumes were used to map a sequence of stacked high-quality landing targets and clearly show the limit of the deep basin sediments to the east onto the basin margin slope. The seismic volumes also shed light on how our offset operators were targeting and drilling their horizontal wells.
While evaluating offset operator wellbore surveys against the reservoir model volumes we noticed large variations in wellbore paths and exposure to high porosity, hydrocarbon charged reservoir rock. These large variations in exposure to the preferred target interval played a large role in the statistical scatter of well results (Figure 1) as well as our model for drilling and completing a more economic well data set.
In early 2017 Tracker began drilling 16 horizontal Wolfcamp wells that were planned using the seismic depth volumes. Well paths were planned to minimize inclination/trajectory changes while avoiding hazards, with the goal of keeping 100% of the lateral in the targeted high-quality zone. Well performance thus far has been excellent when compared to the approximately 615 horizontal wells drilled in the immediate neighborhood. One aspect that has stood out from this analysis is the consistency/similarity in production from the Tracker wells, even though 3 distinct benches were tested. This consistency in results is likely due to the ability to stay in the target zone with minimal inclination changes, large high intensity engineered completions, and detailed flowback procedures which managed drawdown based on bottom hole flowing pressures.
Investors and operators like to draw attention to the lengthy history of oil production from the Permian. Benefits include well-known reservoirs and lower cost brownfield options for services and infrastructure. Today's boom mirrors prior periods of intense Permian activity, but using prior comparisons of tight oil reservoir behavior can result in dangerous conclusions.
The Permian houses thousands of vertical wells that have been online for decades. The actual terminal decline rates of those wells can be modeled with empirical data, and our analysis shows that they sit between 5% and 10% annually. However, pure field data for horizontal tight oil wells does not go back as far, so terminal decline values from vertical wells or general ‘shale’ declines are often applied to Wolfcamp type curves as a proxy. This is a risky practice.
Building evidence suggests that the most active Wolfcamp sub-plays may eventually still have annual decline rates greater than 10% five or more years into their lifespan. Not recognizing this and modeling with the lower proxy value from older, analogue tight oil plays could result in overstating production potential and overvaluing projects. Wolfcamp players without exposure to other basins may need to resort to M&A to fill production gaps. We are already seeing signs of this in 2018 deals with Concho and Diamondback using M&A to acquire larger undrilled acreage footprints.
In many cases, Permian tight oil wells realize more than 40% of the estimated ultimate recovery (EUR) within only 36 months of being online. Nearly 50% net present value (NPV) is realized by year five. Rightfully so, we have observed the analytical focus being placed on each well's first few years. This emphasis has also been driven by the limited number of tight oil wells with more than five years’ worth of production history. Less than 20% in the Permian tight oil wells have been producing more than 60 months.
As the Wolfcamp play matures, the later-life performance of wells starts to matter more. Even with record rig counts, the number of new wells drilled each year becomes a smaller proportion of the total wells contributing to supply.
Euzen, Tristan (IFP Technologies (Canada) Inc.) | Watson, Neil (Enlighten Geoscience Ltd.) | Chatellier, Jean-Yves (Tecto-Sedi Integrated Inc.) | Mort, Andy (Geological Survey of Canada) | Mangenot, Xavier (Caltech)
With the development of unconventional resources, the large number and high density of well data in the deep/distal part of sedimentary basins offer new avenues for petroleum system analysis. Gas geochemistry is a widespread and inexpensive data that can provide invaluable information to better understand unconventional plays. This paper illustrates the use of early production gas composition as a proxy for in-situ hydrocarbon phase distribution in the Montney play of westernmost Alberta and northeastern British Colombia. We demonstrate that a careful stratigraphic allocation of the landing zone of horizontal wells is a key step to a meaningful interpretation and mapping of gas geochemical data. The regional mapping of the dryness of early production gas from the Montney formation clearly delineate thermal maturity windows that are consistent with available carbon isotopic data from produced and mud gas. Integrating this mapping with pressure and temperature data also highlights gas migration fairways that are likely influenced by major structural elements and compartmentalization of the basin. In the wet gas window, reported condensate-gas ratios show that the liquid recovery from multi-stage fractured horizontal wells is highly variable and strongly influenced by variations in reservoir quality and stimulation design. Understanding in-situ fluid distribution can help narrow down the number of variables and identifying key controls on liquid recovery. Several examples combining produced and mud gas data illustrate the use of geochemistry to better constrain geological and operational controls on productivity and liquids recovery in the Montney play.
With the rapid development of unconventional resources, a wealth of new data has been released from historically undrilled or poorly documented portions of sedimentary basins. The large number and high density of well data over extended areas of deep/distal parts of these basins offer invaluable information and new perspectives for petroleum system analysis. In the Montney play of Western Canada, the distal unconventional part of the basin covers an area of approximately 65,000 square kilometers and has been penetrated by over 7,000 horizontal wells. Due to sustained low gas price in North America over the past decade, most of the industry activity has been focused on the liquids-rich gas and light oil fairways of this resource play. Production data show that although a broad liquids-rich fairway can be defined at the basin scale, local variations of fluid distribution and reservoir quality strongly affect the liquid recovery from horizontal wells. The geochemical compositions of both produced gas and mud gas provide a powerful tool to investigate those variations, their geological controls and their impact on well performance. While this paper focuses on the fluid distribution, numerous studies have documented the influence of reservoir quality on the liquid recovery in the Montney play (Chatellier and Perez, 2016; Kato et al., 2018; Akihisia et al., 2018; Iwuoha et al., 2018).
Molinari, Diego (Anadarko Petroleum Corporation) | Sankaran, Sathish (Anadarko Petroleum Corporation) | Symmons, Dave (Wilcox Wiggins Inc.) | Perrotte, Michael (Anadarko Petroleum Corporation) | Wolfram, Edward (Anadarko Petroleum Corporation) | Krane, Ilsa (Anadarko Petroleum Corporation) | Han, Jichao (Anadarko Petroleum Corporation) | Bansal, Neha (Anadarko Petroleum Corporation)
This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Denver, Colorado, USA, 22-24 July 2019. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not necessarily reflect any position of URTeC. Any reproduction, distribution, or storage of any part of this paper by anyone other than the author without the written consent of URTeC is prohibited. Abstract Unconventional resource plays are characterized by a fast pace of development. Hundreds of new wells are drilled, completed and produced rapidly, while exhibiting sharp production declines. It is critical to analyze large amounts of data quickly and effectively, with a holistic view striving for efficient field development and operational excellence. This is essential to extract the most value from available information, while taking into account all wells and optimizing the system as a whole - from reservoir to facility, to ensure the best well performance and productivity, while minimizing failures and downtime. This requires a system that can robustly monitor and optimize a large number of wells quickly under challenging conditions - namely data gaps, sparsity, data quality, uncertain parameters, incomplete knowledge of physics, large scale and rapid pace of operations, among others.