Penn West Exploration (Canada)

Abstract This study introduces a novel leak detection methodology for liquid pipelines, combining a Sequential Probability Ratio Test (SPRT) with a Kantorovich Distance (KD) filter (SPRT-KD). This model enhances leak detection performance over traditional volume balance (VB) systems in the traditional domains of reliability, sensitivity, robustness, and accuracy. The model performs well in complex pipeline networks in real time, addressing limitations of conventional methods under transient conditions. The SPRT-KD integrates a statistical data-driven SPRT model based on volume imbalance for statistical leak detection with a KD filter to detect operational changes. SPRT accumulates evidence of leaks via flow discrepancies, employing slow, medium, and fast time window detection filters, while KD measures shifts in the flow distribution to detect and suppress the effect of transients which could cause false alarms. The process involves continuous monitoring of flow, KD-based anomaly detection, and SPRT score aggregation over short period (15-minute) windows to trigger alarms when thresholds are exceeded. In a case study from a Northern Alberta condensate pipeline (December 2023), the SPRT-KD model detected a 40 m3/day leak (0.6% of 6700 m3/day total flow) in 13 minutes, compared to 3 hours for a VB model, despite high transience in the complicated network. The KD filter eliminated false alarm signals attributed to operational changes. The model maintained signal integrity, with no loss of alarm signal over the entire 10 hour leak period. SPRT-KD demonstrated superior sensitivity (detecting leaks below the flow meter accuracy) and speed compared to a VB model. The SPRT-KD model combines a sensitive data-driven model with the use of a real time rolling KD calculation to identify operational changes. This approach minimizes false alarms in real-world environments, even in highly transient networks with a plurality of inlets and outlets. SPRT-KD offers a significant advancement in statistical leak detection, providing rapid, reliable alerts in transient environments, validated by real-world application.

INTRODUCTION:Patients with ulcerative colitis (UC) and prior biologic failure may have reduced or delayed efficacy with subsequent advanced therapies. This analysis evaluated the efficacy and safety of ozanimod during the True North (TN) study and its open-label extension (OLE) in biologic-exposed patients with UC.METHODS:TN was a randomized, placebo-controlled 52-week trial (10-week induction, 42-week maintenance period). Eligible patients could enter the OLE. Clinical outcomes were assessed at TN week (W) 10 and W52 and OLE W46 and W94. Symptomatic efficacy was evaluated through induction and in the OLE until W94. Safety was assessed.RESULTS:This analysis included 376 biologic-exposed patients. In the placebo-controlled cohort, more ozanimod-treated patients achieved clinical response than placebo at W10 regardless of the number or type of prior biologics; patients who used 1 vs ≥2 prior biologics achieved higher efficacy rates. Efficacy rates were higher at W52 than W10 and were similar across subgroups regardless of the number or type of prior biologics. Significantly greater proportions of ozanimod vs placebo patients achieved symptomatic response by W5 (P = 0.0173) and symptomatic remission by W10 (P = 0.0207). Among biologic-exposed TN W10 ozanimod nonresponders who entered the OLE, 61% achieved symptomatic response with an extra 10 weeks of ozanimod treatment. Ozanimod efficacy was durable for ∼3 years of continuous treatment in biologic-exposed W52 clinical responders who entered the OLE. No new safety signals were observed.DISCUSSION:Ozanimod was effective and safe in biologic-exposed patients with UC, but these patients may require more time to respond to treatment. Clinical trial registry website and trial numbers: ClinicalTrials.gov, numbers NCT02435992 and NCT02531126.

We evaluated the concept of surface-consistent matching filters for processing time-lapse seismic data, in which matching filters are convolutional filters that minimize the sum-squared error between two signals. Because in the Fourier domain a matching filter is the spectral ratio of the two signals, we extended the well-known surface-consistent hypothesis such that the data term is a trace-by-trace spectral ratio of two data sets instead of only one (i.e., surface-consistent deconvolution). To avoid unstable division of spectra, we computed the spectral ratios in the time domain by first designing trace-sequential, least-squares matching filters, then Fourier transforming them. A subsequent least-squares solution then factored the trace-sequential matching filters into four operators: two surface-consistent (source and receiver) and two subsurface-consistent (offset and midpoint). We evaluated a time-lapse synthetic data set with nonrepeatable acquisition parameters, complex near-surface geology, and a variable subsurface reservoir layer. We computed the four-operator surface-consistent matching filters from two surveys, baseline and monitor, then applied these matching filters to the monitor survey to match it to the baseline survey over a temporal window where changes were not expected. This algorithm significantly reduced the effect of most of the nonrepeatable parameters, such as differences in source strength, receiver coupling, wavelet bandwidth and phase, and static shifts. We computed the normalized root mean square difference on raw stacked data (baseline and monitor) and obtained a mean value of 70%. This value was significantly reduced after applying the 4C surface-consistent matching filters to about 13.6% computed from final stacks.

The last few decades have witnessed greater exploration of oil and gas developments and improvements and evolution in technology that have been driven by the strong demand for oil and gas. Hydralic fracturing techniques have become subject to scrutiny by the media and public in North America and Europe, with attention being paid to the potential or perceived environmental impact associated with such technological developments. This article explains the context and process in which horizontal multi-stage fracturing (HMSF) functions. In addition, the article explores and outlines the legal and regulatory environments in both Canada and the United States, where issues have been raised owing to the wider use of HMSF. The article seeks to provide readers with a better understanding of these emerging and potential legal and regulatory issues.

Abstract Development of tight or low permeability reservoirs (e.g. Bakken formation) commences to reveal its potential and significance and expected to become even more essential in the future. The Canadian Bakken has been produced for over 40 years. At present, the combination of horizontal well drilling and the new multi-stage fracturing and completion technologies has been the key to economically unlocking the vast reserves of the Bakken formation. Parametric studies of fracture geometry on well productivity and oil recovery are essential for a successful hydraulic fracturing stimulation treatment. In this paper, we will investigate the best hydraulic fracturing scenario for Bakken formation and the effects of fracture geometries on oil recovery. More specifically, a geological model is firstly built using typical fluid and rock properties in Bakken formation; the horizontal wells with multistage hydraulic fractures will then be modeled using local grid refinement (LGR) and history matched based on the field production data. Various fracture treatment designs are evaluated, which include the investigation of various fracture spacing, lengths, and fracture locations on the horizontal wells. The results of this study show that, employing multistage hydraulic fracturing along horizontal wells can significantly improve oil recovery in Bakken formation. Compared to fracture length, fracture spaces or fracture numbers have greater impacts on oil recovery. More importantly, for the same fractured volume in the reservoir (i.e., the same usage of proppant and fracturing fluid), fractures with longer and smaller fracture numbers lead to a similar oil recovery compared to shorter but larger fracture numbers along the horizontal well laterals.

Abstract Recent advances in well design and production techniques have brought considerable attention to exploitation of tight (low permeability, absolute permeability <1 mD) oil resources. Drilling of long horizontal wells and deployment of hydraulic fractures along these wells (multi-fractured horizontal wells) can substantially improve the primary production rates from such reservoirs. Nevertheless, the low effective permeability of these reservoirs to oil hinders the sustainability of favorable oil rates and at some point applying some EOR technique becomes inevitable. In the current study, CO2 miscible flooding and WAG process in a tight oil reservoir are investigated. Although several studies have investigated different aspects of the process in conventional oil plays, the design of an effective scheme in tight oil formations is more complex. These complexities are related to the proper design of the fractures (half-length, conductivity, orientation (transverse vs. longitudinal), etc.) and their relative placement along producers and injectors and the operational constraints on each well or segment of the well. In this work, we utilize an EOR scheme design where multi-fractured horizontal wells are used for both injection and production, and the hydraulic fracturing stages are staggered to delay breakthrough and improve sweep efficiency. For a set of defined parameters, compositional simulations are conducted to investigate the effect of the CO2 slug size, WAG ratio and cycle length on the recovery efficiency of the model. The recovery from the aforementioned EOR process is then compared with its corresponding base case in which the reservoir has gone through periods of primary and water-flooding stages. The results of this study show that the incremental oil recovery from WAG process in tight formation can reach as high as 20%.

Frequency-dependent seismic field data anomalies, appearing in association with low-[Formula: see text] targets, have, on occasion, been attributed to the presence of a strong absorptive reflection coefficient. This “absorptive reflectivity” represents a potent, and largely untapped, source of information for determining subsurface target properties. It would most likely be encountered where a predominantly elastic/nonattenuating overburden suddenly is interrupted by a highly attenuative target. Series expansions of absorptive reflection coefficients about small parameter contrasts and incidence angles can expose these anomalies to analysis, either frequency-by-frequency (amplitude variation with frequency [AVF]) or angle-by-angle (amplitude variation with angle of incidence [AVA]). Within this framework, variations in P-wave velocity and [Formula: see text] can be estimated separately through a range of direct formulas, both linear and with nonlinear corrections. The latter come to the fore when a contrast from an incidence medium [Formula: see text] (i.e., acoustic/elastic) to a target medium [Formula: see text] is encountered, in which case the linearized estimate can be in error by as much as 50%. Algorithmically, it is a differencing of the reflection coefficient across frequencies that separates [Formula: see text] variations from variations in other parameters. This holds for both two-parameter (P-wave velocity and [Formula: see text]) problems and five-parameter anelastic problems, and would appear to be a general feature of direct absorptive inversion.

Abstract The CO2 miscible flood project in the Joffre Viking pool is unique. It was the first commercial CO2 flood in Canada and is a true tertiary oil recovery application from an abandoned waterflood project. The project uses waste CO2 from the adjacent NOVA chemical plant, as miscible solvent. A significant amount of CO2 has been sequestrated in the Joffre Viking pool. The project is a technical and economical success with tertiary oil recovery ranging 12 – 25 percent of the original oil-in-place for diverse developmental patterns. This paper summarizes the development history of the project and illustrates the effectiveness of CO2 and water injection in terms of oil recovery and CO2 utilization. This paper also demonstrates the importance of reservoir monitoring to optimize sweep efficiency, as the patterns become mature. Even after 19 years since the initial pilot program, the project still produces a significant volume of oil economically. Penn West Petroleum Ltd., the main working interest owner and operator, is currently proceeding with pattern expansion within the Joffre Viking Tertiary Oil Unit. Introduction Penn West Petroleum Ltd. operates the CO2 miscible flood project in the Joffre Viking Tertiary Oil Unit (JVTOU), northeast of Red Deer, Alberta, Canada (Figure 1). This is the only commercial CO2 flood project in Alberta. Since the original two pattern pilot program in 1984, the CO2 flooding has been progressively expanded. The project is currently composed of 13 CO2 injection patterns with 32 oil producers, 14 CO2 injectors and 3 fence peripheral water injectors, as shown in Figure 2. About 70% of the JVTOU is under CO2 miscible flooding. Penn West is currently undertaking pattern expansion into the undeveloped part of the unit. The CO2 project has been effective in recovering tertiary oil with cumulative oil production of 580 × 103 m3. It is currently producing oil at 100 m3/d with 265 × 103 sm3/d CO2 injection. The project has experienced early CO2 breakthrough. Typical water-alternating-gas (WAG) process does not control CO2 fingering effectively in the JVTOU. Simultaneous CO2-water injection seems to stabilize CO2 fingering much better, improving areal sweep efficiency. In addition to the review on the project geology and development history, this paper discusses the practical aspects of reservoir monitoring and optimization including the performance of individual injection patterns, critical monitoring parameters, mobility control and the current pattern expansion. Geology The Joffre Viking oil is trapped stratigraphically in an elongated barrier sand bar, which is 32 km long and 1.5 – 3.5 km wide. Sediments of the Lower Cretaceous Viking Formation in the Joffre area were deposited as coarse grained to conglomeratic, northwest-southeast trending clastic sand bodies. The Albian aged Viking formation overlays the marine shales of the Joli Fou and is, in turn, overlain by transgressive marine shales of the Colorado Group. The Viking sands in the Joffre area appear to be transgressive shoreface deposits that are often erosionally truncated during sea-level falls. The Viking sands have a shore-parallel orientation, with the shoreline to the southwest and the marine basin towards the northeast.

Proppants, We Still Don't Need No Proppants - A Perspective of Several Operators Ray N. Walker, Jr.; Ray N. Walker, Jr. Union Pacific Resources Co. Search for other works by this author on: This Site Google Scholar Jeffery L. Hunter; Jeffery L. Hunter Pennzoil Exploration and Production Co. Search for other works by this author on: This Site Google Scholar Al C. Brake; Al C. Brake Amoco Search for other works by this author on: This Site Google Scholar Paul A. Fagin; Paul A. Fagin Valence Operating Co. Search for other works by this author on: This Site Google Scholar Nick Steinsberger Nick Steinsberger Mitchell Energy Corp. Search for other works by this author on: This Site Google Scholar Paper presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, September 1998. Paper Number: SPE-49106-MS https://doi.org/10.2118/49106-MS Published: September 27 1998 Cite View This Citation Add to Citation Manager Share Icon Share Twitter LinkedIn Get Permissions Search Site Citation Walker, Ray N., Hunter, Jeffery L., Brake, Al C., Fagin, Paul A., and Nick Steinsberger. "Proppants, We Still Don't Need No Proppants - A Perspective of Several Operators." Paper presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, September 1998. doi: https://doi.org/10.2118/49106-MS Download citation file: Ris (Zotero) Reference Manager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex Search Dropdown Menu nav search search input Search input auto suggest search filter All ContentAll ProceedingsSociety of Petroleum Engineers (SPE)SPE Annual Technical Conference and Exhibition Search Advanced Search AbstractIn SPE 38611 "Proppants, We Don't Need No Proppants" data showed that fracture treatments using treated water and very low proppant concentrations (waterfracs) were very successful in the East Texas Cotton Valley sandstone. The paper presented limited initial results from one operator in one field. Following this paper a more comprehensive set of production comparisons of wells completed with standard frac jobs and waterfracs since 1996 for several different operators in the East Texas area are presented. Analysis of offset comparisons, economics, and other benefits are described from the aspect of several different operators.Conclusions will point out the cost savings and the ability to exploit marginal reserves with this technique. There will also be a perspective from each operator. The waterfrac technique has led to widespread discussions among many operators in various tight gas plays. Many operators are experimenting with the technique and experiencing excellent results. This technique is a major contribution to the reduction in completion costs in wells that must be hydraulically fractured. The industry has experienced a major inflation of well construction costs and this technique will be of paramount importance in our efforts to keep costs down in order to continue to develop tight gas reserves. Techniques such as these require many months of production in order to analyze to determine the actual results. Several techniques and the perspectives of several operators and how they make these important decisions will be presented here.P. 497 Keywords: upr, gel treatment, east texas, conductivity, operator, watcrfrac, hydraulic fracturing, valence, fracturing fluid, cotton valley Subjects: Hydraulic Fracturing, Fracturing materials (fluids, proppant) This content is only available via PDF. 1998. Society of Petroleum Engineers You can access this article if you purchase or spend a download.