Se, Yegor (Chevron Energy Technology Company) | Villegas, Mauricio (Chevron) | Iskakov, Elrad (Chevron) | Playton, Ted (Tengizchevroil) | Lindsell, Karl (Tengizchevroil) | Cordova, Ernesto (Chevron Energy Technology Company) | Turmanbekova, Aizhan | Wang, Haijing
Secondary oil recovery projects in naturally fractured carbonate reservoirs (NFR) often introduce uncertainties and challenges that are not common to conventional waterfloods. The recovery mechanism in NFRs relies on ability of the fracture network to deliver enough injected fluid to the matrix, as well as rate and magnitude of capillary interactions within the matrix rock, during which hydrocarbon displacement occurs. The imbibition measurements can be performed in the laboratory using core samples, but due to reservoir heterogeneity, certain limitations of the lab equipment and the quality of the core material, scalability of the core results to a reservoir model can be challenging.
This paper describes the design, execution and evaluation of the’ log-soak-log’ (LSL) pilot test conducted in a giant naturally fractured carbonate reservoir with a low-permeability matrix in Western Kazakhstan, where repeatable and reliable measurements of changes in water saturation were achieved across large intervals (tens of meters) using a time-lapse pulsed-neutron logging technique. Periodic measurements provided valuable observations of dynamic change in saturation and fluid level over time and allowed estimation of the rate and magnitude of imbibition in the slope margins, depositional settings and rock types of interest. Incorporation of the LSL results into reservoir models validated the ranges of water-oil relative permeability curves, residual oil saturation to water, irreducible water saturation, and capillary pressure assumptions. This validation constrained key subsurface uncertainty and updated the oil recovery forecast in several improved oil recovery (IOR) waterflood projects.
JPT Technology Minute Poll: To Which of the Top Five UN Sustainability Development Goals Do You Think the Oil and Gas Industry Will Contribute the Most? The papers identified in the article cover sustainable development of oil and gas resources in various aspects. Flaring and emissions challenges have recently made news headlines around the world. The goal of this article is to engage you with this important topic by presenting a selection of recent SPE papers which address these challenges through various approaches. Operators face a dilemma in balancing the need for mud weight (MW) to remain below the fracture gradient to avoid losses, while also providing sufficient density to block influxes into the well. JPT Technology Minute Poll: Which Technology Would You Choose for Offshore Compression?
This page pulls together technology-focused articles from various departments within JPT. This paper introduces a new core-analysis work flow for determining resistivity index (RI), formation factor (FF), and other petrophysical properties directly from an as-received (AR) set of core samples. In this paper, the authors discuss the characterization process for GR tools and how they behave in boreholes different from the one used in the University of Houston (UH) GR characterization pit. This paper discusses a study undertaken to gain better understanding of nuclear magnetic resonance (NMR) characteristics of volcanic reservoirs with different lithologies. Formation evaluation drew special attention at the 2019 International Petroleum Technology Conference Education Week in Beijing, 24–28 March 2019. The student team that worked on Integrated Formation Evaluation for Resources Exploration and Reservoir Delineation won the first-place award. The first subsea multiphase boosting system was installed in 1994.
PETRONAS FLNG SATU (PFLNG1) is a floating liquefied natural gas facility producing 1.2 million tonnes per annum (mtpa) of LNG, on a facility that is 365m long, and 60m wide, making it among the largest offshore facility ever built. The PFLNG1 project is the first of its kind in the world and is the first deployment of PETRONASâ€™ Floating Liquefied Natural Gas (FLNG) technology, consolidating the traditional offshore to onshore LNG infrastructure into a single facility. This will see a giant floating facility capable of extracting, liquefying and storing LNG at sea, before it is exported to customers around the globe. The FLNG journey has come a long way since 2006, with many technological options explored to monetise and unlock the potential of small and stranded gas fields. Moving an LNG production to an offshore setting poses a demanding set of challenges â€“ as every element of a conventional LNG facility needs to fit into an area roughly one quarter the size in the open seas whilst maintaining safety and increased flexibility to LNG production and delivery. The keynote address describes the breakthrough features of PFLNG1 â€“ the worldâ€™s first floating LNG facility; and the pioneering innovation that it brings to the LNG industry.
The current presentation date and time shown is a TENTATIVE schedule. The final/confirmed presentation schedule will be notified/available middle of October 2019. If we have learned anything from the North American experience, unconventional resources cannot be exploited by small incremental projects. If we are to be successful in developing these types of reservoirs, we have to make project scale operations work to bring these resources to market in a timely manner. A number of Eastern Hemisphere unconventional gas projects have raised interest, neared completion or are commencing deliveries.
Africa (Sub-Sahara) Mazarine Energy has started a two-well drilling campaign in the Zaafrane permit in central Tunisia. The first well, Cat-1, has been spudded and is targeting the Ordovician interval at a planned total depth of 3900 m. Mazarine (45%) is the operator with partners ETAP (50%) and MEDEX (5%). Asia Pacific China National Offshore Oil Company (CNOOC) has made a natural gas discovery at its deepwater Lingshui 25-1 well, northeast of Ledong sag in the South China Sea's Qiongdongnan basin, where the average water depth is 980 m. The well was drilled to a depth of 4000 m and encountered 73 m of oil and gas pay. During a test, the well produced approximately 35 MMcf/D of natural gas and 395 BOPD. CNOOC holds full operated interest in the license.
Case studies can be instructive in the evaluation of other coalbed methane (CBM) development opportunities. The San Juan basin, located in New Mexico and Colorado in the southwestern U.S. (Figure 1), is the most prolific CBM basin in the world. It produces more than 2.5 Bscf/D from coals of the Cretaceous Fruitland formation, which is estimated to contain 43 to 49 Tscf of CBM in place. For a long time, the Fruitland formation coals were recognized only as a source of gas for adjacent sandstones. In the 1970s, after years of encountering gas kicks in these coals, operators recognized that the coal seams themselves were capable of commercial gas rates. CBM development benefited greatly from drilling and log data compiled from previous wells targeting the deeper sandstones and an extensive pipeline infrastructure that was built to transport conventional gas. These components, along with a U.S. federal tax credit and the development of new technologies such as openhole-cavity completions, fueled a drilling boom that resulted in more than 3,000 producing CBM wells by the end of 1992. The thickest Fruitland coals occur in a northwest/southeast trending belt located in the northeastern third of the basin. Total coal thickness in this belt locally exceeds 100 ft and individual coal seams can be more than 30 ft thick. The coals originated in peat swamps located landward (southwest) of northwest/southeast trending shoreline sandstones of the underlying Pictured Cliffs formation. The location of the thickest coals (Figure 1) coincides with the occurrence of overpressuring, high gas content, high coal rank, and high permeabilities in the San Juan fairway ("fairway"). The overpressuring is artesian in origin and is caused by water recharge of the coals through outcrops along the northern margin of the basin. This generates high vertical pressure gradients, ranging from 0.44 to 0.63 psi/ft, which allow a large amount of gas to be sorbed to the coal. Coal gas in the San Juan basin can contain up to 9.4% CO2 and 13.5% C2 . Chemical analyses suggest that thermogenic gases have been augmented by migrated thermogenic and secondary biogenic gas sources, resulting in gas contents ranging up to 700 ft 3 /ton. Coal rank in the fairway ranges from medium- to low-volatile bituminous and roughly coincides with those portions of the basin that were most deeply buried. Coals in the fairway typically have low ash and high vitrinite contents, resulting in large gas storage capacities and excellent permeabilities of 10 md from well-developed cleat systems.
Maintaining a stable borehole and optimizing drilling are still considered to be vital practice for the success of any hydrocarbon field development and planning. The present study deliberates a case study on the estimation of pore pressure and fracture gradient for the recently decommissioned Volve oil field at the North Sea. High resolution geophysical logs drilled through the reservoir formation of the studied field have been used to estimate the overburden, pore pressure, and fracture pressure. The well-known Eaton’s method and Matthews-Kelly’s tools were used for the estimation of pore pressure and fracture gradient, respectively. Estimated outputs were calibrated and validated with the available direct downhole measurements (formation pressure measurements, LOT/FIT). Further, shear failure gradient has been calculated using Mohr-Coulomb rock failure criterion to understand the wellbore stability issues in the studied field. Largely, the pore pressure in the reservoir formation is hydrostatic in nature, except the lower Cretaceous to upper Jurassic shales, which were found to be associated with mild overpressure regimes. This study is an attempt to assess the in-situ stress system of the Volve field if CO2 is injected for geological storage in near future.
The Cooper Basin of Australia is challenged by strike-slip to reverse stress regimes, adversely affecting hydraulic fracturing treatments. In drilling, the high deviatory stress conditions increase borehole breakout, affect log acquisition and impact cementing job quality. The non-favourable stress conditions in conjunction with natural fracturing result in: complex fracturing (with shear and sub-vertical components); high near-wellbore pressure loss (NWBPL) values; and stimulation of lower permeability, low modulus intervals (e.g., carbonaceous shales, interbedded coals) in preference to the targeted and higher modulus, tight-gas sandstones. Typically, vertical wells have been employed in past completions of the Cooper Basin as well as in the offsetting areas to the case study in the Windorah Trough, Southwest Queensland.
We will present the results from two case study wells offsetting a previous vertical well where well trajectory, completion and fracture design changes were employed in an ongoing experiment to improve job execution for Patchawarra tight gas reservoir treatments in the Cooper Basin. The two wells were directionally deviated at 31° and 25° final inclinations from vertical with azimuth <10 deg from the maximum horizontal stress direction, as determined from offsetting well data. To better define sections with limited, poor or missing log data (because of difficult hole conditions), drilling data, logging while drilling (LWD) gamma ray data, openhole conventional and dipole sonic logs, along with prior 1D stress data were used with a machine learning model to improve stress profiling and reservoir characterization. Next, perforations were shot 0 and 180° phased along the wellbore and initial fluid viscosity was increased to better align the hydraulic fracture and reduce NWBPL, respectively. Finally, diagnostic fracture injection tests (DFIT) were performed in sections of varying moduli below and in the zone of interest in order to verify the horizontal strains and calibrate the final 1D stress profile prior to stimulating both wells.
The improved well and perforation alignment to the maximum horizontal stress direction has improved reservoir connection, lowered NWBPL in some cases, and in some cases improved fracture containment. Decreasing injection rates and minimizing perforated intervals has improved targeting of desired intervals; however, overall fracture widths remain low and continue to be sensitive to proppant sizing and concentrations with several screen outs experienced. This experimentation has resulted in short-term production improvements in the wells using 4- and 3-stage treatments relative to the offsetting vertical well where a 5-stage treatment was executed.
Significantly different inputs are considered in deriving rock mass shear strength via Hoek-Brown Method (HBM) and Step-Path Method (SPM) approaches. The HBM cannot effectively assess the directional strength in rocks. Conversely, the key objective of the SPM is to consider the relative strength impact of the geological defects that are near co-aligned with part(s) or full length of critical failure paths through rock masses. Defect attributes considered in SPM are their orientation, relative occurrence, likelihood of cut-off by other defects, presence of intact rock and/or rock mass bridges between non cut-off defects and shear strength.
Where applicable by the structural conditions in the rock mass, the SPM strength may be 40-50% less than the equivalent HBM strength. However, SPM approach does require a more comprehensive understanding of the structural conditions in the rock mass and a greater analysis effort to develop the shear strength parameters.
In the SPM, the rock mechanics problem is partitioned into structural domains. Each domain is associated with a specific geological defect set that is approximately co-aligned with the anticipated critical failure path through this domain. General HBM conditions apply in those domains where no defect set is co-aligned with the failure path. In domains where the SPM is relevant, the conventional Hoek-Brown Geological Strength Index (GSI) chart values are adjusted for probability of occurrence, cut-off and length of bridges between non cut-off defects of those defect set(s) that impact rock mass strength outcomes.
The logic, methodology and step-by-step procedure for adjusting the Hoek-Brown GSI chart to derive SPM outcomes are described in detail. Example adjustments are presented to better illustrate the involved process.
The Hoek-Brown Method (HBM) for shear strength of rock masses was first published by Hoek and Brown (1980). HBM considers the intensity of rock mass ‘structure’ (blockiness) and ‘condition’ of geological defect surfaces. The same strength is computed for all directions through the rock mass.
Contrary to this initial HBM non-directional strength premise, failure paths are often structurally controlled and coincide with geological defects co-aligned with path directions. Some paths may be almost entirely defined by geological defects with only minor shearing through intact rock and/or rock mass ‘bridges’ between defects. To address HBM directional strength limitation, several authors revised the Geological Strength Index (GSI) chart to consider foliated rocks. These revisions are mostly qualitative; not quantitative.