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Sempra Energy’s Energía Costa Azul LNG (ECA LNG) subsidiary reached a final investment decision (FID) to build its $2-billion Phase 1 natural gas liquefaction export project in Baja California, Mexico. ECA LNG, a joint venture between Sempra LNG and its Mexico subsidiary IEnova, is the only LNG export project to reach FID in 2020, and is slated to be the first on the Pacific Coast of North America. The facility will connect natural gas supply from Texas and the western US to Mexico and other countries across the Pacific Basin. First production from Phase 1 is expected in late 2024. The company secured a 20-year supply agreement with Mitsui and an affiliate of Total for the purchase of 2.5 mtpa and is working with Total for a potential equity investment in the facility.
SPE’s A Peer Apart award recognizes those dedicated individuals involved in the review of 100 or more papers for SPE’s peer-reviewed journals. Peer review is an essential part of scientific publishing and helps to ensure the information contained in a journal is well supported and clearly articulated. Volunteers who commit their time to review papers make substantial contributions to the technical excellence of our industry’s literature. Each year SPE typically has more than 1,400 individual reviewers submitting more than 3,500 reviews for SPE’s various journals. These committed volunteers come from a variety of backgrounds, including academia, service and operator companies, and consultancies from around the world.
Johnson, Raymond L. (University of Queensland) | You, Zhenjiang (University of Queensland) | Ribeiro, Ayrton (University of Queensland) | Mukherjee, Saswata (University of Queensland) | Salomao de Santiago, Vanessa (University of Queensland) | Leonardi, Christopher (University of Queensland)
Defining pressure dependent permeability (PDP) behaviour in coalbed methane (CBM) or coal seam gas (CSG) reservoirs using reservoir simulation is non-unique based on the uncertainty in coal properties and input parameters. A diagnostic fracture injection test (DFIT) can be used to investigate bulk permeability at a reservoir level and at lowered net effective stress conditions. As coal has minimal matrix porosity and under DFIT conditions cleat porosity is fluid saturated with reasonably definable total compressibility values, the DFIT data can provide insight into PDP parameters. At pressures above the fissure opening pressure, pressure dependent leak off (PDL) behaviour increases exponentially with increasing pressure. Many authors have noted that with decreasing pressure PDP declines exponentially with increasing net effective stress. Thus, PDP behaviour can be defined by PDL.
In this paper, we show how combined analyses, using typically collected field data, can be used to better define and constrain the modelling of PDP. We illustrate this process based on a well case study that includes the following data: fracture fabric and porosity reasonably defined from image log and areal core studies; DFIT data acquired under initial saturation conditions; hydraulic fracturing data; and longer term production data. These analyses will be integrated and used to constrain the parameters required to obtain a rate and pressure history-match from the post-frac well production data.
This workflow has application in other coal seam gas cases by identifying key variables where hydraulic fracturing performance has been unable to overcome limitations based on pressure or stress dependent behaviours and often accompanied by low reservoir permeability values. While this is purposely targeting areas where only typically collected field data is available, this workflow can include coal testing data for matrix swelling/shrinkage properties or other production data analysis techniques.
Jing, Cui (Sichuan Changning Natural Gas Development Co., Ltd.) | Chen, Yanyan (Schulmberger) | Jing, Xianghui (Research Institute of Exploration and Development, PetroChina Changqing Oilfield Company) | Wang, Bing (Schulmberger) | De, Heng (Sichuan Changning Natural Gas Development Co., Ltd.) | Huang, Zheyuan (Schulmberger) | Wen, Ran (Sichuan Changning Natural Gas Development Co., Ltd.) | Zhang, Caiyun (Schulmberger) | Zhou, Nie (Sichuan Changning Natural Gas Development Co., Ltd.)
The highly complex geology of the Sichuan Shale gas play, especially in relation to natural fracture systems at different scales, affects the hydraulic completion efficiency and performance. Ant-tracking-based workflows and borehole image data are regularly used to optimize completion campaigns, but bridge-plug-stuck and screen-out risks are still high. The lack of sufficient understanding and accurate identification of the natural fracture systems are the major challenges to address these engineering risks.
Surface microseismic monitoring campaigns were conducted over several wells of the Changning field, Sichuan Basin, China. The surface receivers were placed in a radial pattern to record microseismicity generated by hydraulic fracturing. The failure mechanism of all mapped microseismic events (i.e., strike, dip, rake, etc.) was extracted using a moment tensor inversion (MTI) method. Improved understanding of the natural fracture systems and their influence during the hydraulic fracturing process has been achieved by integrating the regional geological data, pumping data and MTI results.
Several hydraulic fracturing cases that stimulated near natural fracture systems were investigated. The microseismic monitoring results show that (i) most of the hydraulically induced fractures located in the vicinity of the natural facture or fault did not propagate along the regional maximum stress direction, (ii) the bridge plug got stuck and (iii) screen-out happened frequently in these areas. Moment tensor inversion reveals that (i) the dominant failure mechanism of the natural fractures different from hydraulically induced fractures, (ii) more than one group of natural fractures develop along different directions.
Real-time adjustments of the pumping schedule and bridge-plug settings were conducted to reduce engineering risks based on the improved understanding of natural fractures, which proved effective. The innovation of using surface microseismic monitoring results to improve understanding of natural fractures and reduce the engineering risks in real time represents a key step forward to mitigate natural fracture influence and improve the effectiveness of stimulation.
M. Al-Dhafeeri, Abdullah (Saudi Aramco) | M. Al-Enezi, Bader (Khafji Joint Operations) | A. Atwa, Elessawy (Khafji Joint Operations) | A. Al-Aklabi, Sultan (Khafji Joint Operations) | Fouad Abo Zkery, Shebl (Khafji Joint Operations) | A. Al Sdeiri, Saad (Khafji Joint Operations)
Operation philosophy at an offshore field is relying on gas lift wells as an artificial lift. The contribution of gas lift wells is essential to achieve the Maximum Sustainable Capacity (MSC). Gas lift system included high- pressure gas piping network system to supply the required gas volume from onshore gas plant, which connected to offshore gathering facilities to feed oil producer wells. Dry gas source obtained from onshore compression plant through 12" high- pressure gas line with 1,250 psi. The major challenge is to preserve the gas-piping network and gas lift wells at a safe manner and a cost-effective approach. An attempt was made to maintain a minimum pressure at value of 150 psi in order to minimize a risk related to pipeline collapse and to shipment collusion at offshore area. A new approach was utilized to bleed off the high-pressure gas network and casing annulus of gas lift wells from operating value of 1,250 psi to the required pressure value of 150 psi. This approach was managed thorough the gas lift pipeline network as loops in terms of pressure and pipeline connection. Each pipeline loop consists of four inter-connected lines ended by one gas lift well at wellhead jacket. The results showed a successful preservation approach to bleed-off high-pressure gas lift wells with connected pipelines occupied with large volume of dry gas at a cost effective and a safe manner. A self-elevating service vessel was utilized to perform the task with proper procedures and safety measurements. The production casings which were occupied with high volume of dry gas had been successfully bled down at an acceptable pressure to ensure well integrity. The approach covered 20 loops related to offshore gas lift network pipelines at safe and cost effective manner. The new technique added a great value on preservation methodology in term of the released high-pressure gas from gas lift network and producer wells to resolve issues related to air emission and hazard potential through the surface testing equipment with its burner. Challenges, methodology, risk assessment, work schedule, findings and lesson learned will be discussed in this paper.
The first rendering of what is to be the world’s largest direct-air-capture-plant in the Permian Basin. The facility is expected to capture up to 1 million metric tons of CO2 annually for enhanced oil recovery operations in Texas. Occidental Petroleum (Oxy) announced this week that it is joining the race to net-zero carbon emissions. The first step will be to eliminate or offset emissions from its own operations by 2040. The more ambitious leap will require the Houston-based company to do the same for all the oil and gas products it sells by 2050.
As the shale development activity in the Permian continues to be strong and oil prices recover, increasing numbers of infill child wells are being drilled as operators want to improve recovery from each section and continue to meet their production targets. However, production data suggests that both parent and child wells suffer from production losses if they are located too close to one another.
The cube model concept, which is also referred to as supersize fracturing, was first introduced about two years ago and has been piloted in the Permian Basin. In a cube model, multiple wells, usually more than 30 horizontal wells with five to six wells in each different horizontal layer, are drilled and completed in the same section. Operators produce those wells simultaneously with the objective of mitigating the parent-child effect of unconventional reservoirs.
Nevertheless, with all wells producing at the same time and competing for production from the first day, will this benefit ultimate recovery? This question was investigated through comprehensive fracture and reservoir modeling and simulation. A reservoir dataset for the Spraberry Formation in the Permian Basin was used to build a hydraulic fracture and reservoir simulation model.
Different field development strategies were studied. Models representing a traditional parent-child scenario with five parent wells completed and produced one year before four infill child wells and a traditional parent-child scenario with five parent wells completed and produced five years before four infill child wells are compared. In these cases, a geomechanical finite-element model (FEM) was used to quantify the changes to the magnitude and azimuth of the in situ stresses from the various reservoir depletion scenarios. Next, a cube model with nine horizontal wells completed and produced simultaneously was analyzed. These three scenarios were expanded to include 19 horizontal wells with the same methodology.
This study aims to help operators in the Permian Basin, as well as in other unconventional reservoirs to understand how different field development strategies affect ultimate hydrocarbon recovery and net present value.
Sajjad, Farasdaq Muchibbus (PT Pertamina Hulu Energi) | Wirawan, Alvin (PT Pertamina Hulu Energi) | Chandra, Steven (Institut Teknologi Bandung) | Ompusunggu, Janico Zaferson Mulia (PT Pertamina Hulu Energi) | Prawesti, Annisa (PT Pertamina Hulu Energi) | Suganda, Wingky (PT Pertamina Hulu Energi) | Muksin, M. Gemareksha Jamaluddin (PT Pertamina Hulu Energi) | Amrizal, Amrizal (PT Pertamina Hulu Energi)
Tubular engineering design is essential for production operation, especially in the mature oil and gas fields. The complex interaction among oil, natural gas, and water, complemented with wax, scale, inorganic compound, and deformation brings complexity in analyzing tubular integrity. This challenging problem will be more severe if the wells are located in offshore environment, therefore finding the cause of tubing deterioration is a challenging.
Field X, which has been in production for 30 years, cannot avoid the possibility of tubular thinning and deformation. The degradation is slowly developed until severe alterations are observed on the tubing body. The current state of the wells is complicated since the deformation inhibits the fluid flow and increases the risk of wellbore collapse and complications during sidetracking, infill drilling, workover, and other production enhancement measures. The risks can be harmful in the long run if not mitigated properly.
The current condition encourages us to conduct more comprehensive study on tubular degradation. It is to model the multiple degradation mechanisms, such as corrosion, scaling, and subsidence, under the flowing formation fluid. The model is then coupled with reservoir simulation in order to provide a better outlook on tubular degradation. We used multiple case studies with actual field data to identify the dominant mechanism on tubular degradation. The case study cover various reservoir and fluid characteristics and also operations problems to develop general equation and matrix for risk analysis and field development considerations.
We present the degree of tubular degradation and its effect to overall field performance and economics. Current field practices do not encourage a thorough tubular assessment during early life of the wells, which create complex problem at later stage. The study indicates that a proper planning and preventive action should be performed gradually before tubular degradation becomes severe. The paper presents a field experience-based model and guideline matrix that is useful in developing new areas from the perspective of well and facilities integrity, so that the degradation-related issues could be recognized earlier.
Tingate, Peter (National Offshore Petroleum Titles Administrator) | Monro, Jodie (National Offshore Petroleum Titles Administrator) | Pereira, Eric (National Offshore Petroleum Titles Administrator) | Webb, Melanie (National Offshore Petroleum Titles Administrator) | Hamp, Roland (PRM Pty. Ltd)
Australia's National Offshore Petroleum Titles Administrator (‘NOPTA’) has completed a project to gain more detailed insights from field development and performance monitoring of Australian offshore gas developments in Commonwealth waters (excluding state and Northern Territory coastal waters). These insights help identify benchmarks for optimum long-term recovery and aspects of good oilfield practice when evaluating existing and future gas field developments. The methodology applied, high-level metrics, example analysis plots and key insights are discussed.
A new confidential in-house Field Benchmarking Database (‘Database’) has been built, collating a large subset of Australian offshore gas field data acquired by NOPTA from titleholders. The key datasets include field and reservoir properties, facilities data, development timelines and development costs. The Database also references reserves information, production data and estimated ultimate recovery, thereby allowing for quantified analysis and assessment of offshore gas fields in Commonwealth waters within a variety of subsurface, development, operational and commercial contexts.
Data set correlations based on actual and planned long-term gas field performance, capital investment, and resource recovery are utilised to create a range of benchmarking plots focussed on production efficiency, recovery efficiency, schedule efficiency and cost efficiency. A number of key insights from these metrics are presented.
The approach presented lends itself to all petroleum resources within Australian waters. However, this exercise has focussed on gas fields where there are a large number of data (e.g. within each basin, reservoir age, etc.) and where there is a diversity of field performance experience.
Consistent with NOPTA's role and resource management objectives, the new Database and workflows enable efficient analysis of past, present and future field developments. This facilitates the ongoing assessment of developed and undeveloped field performance with regard to recovery, production, capital and schedule efficiencies. Thus, improvement opportunities can be identified.
Although the Database which underpins these insights represents a high-level view of the field and project performance data, it demonstrates the key influencing effects of reservoir quality, resource size and field location. The outcomes of benchmarking are also used to support more performance improvement focussed discussion between the NOPTA and titleholders. Additionally, the benefits of improved recovery initiatives as well as late life investments can be evaluated.
Existing commercial databases and benchmarks do not have a comprehensive dataset of regional analogues specific to Australian offshore petroleum resources, particularly for gas field developments. The derived insights are practically useful and valuable for both titleholders and NOPTA, with the shared objective of delivering continuous improvement in optimum long-term recovery and good oilfield practice.
Sato, Ken (Waseda University) | Shinohara, Kenji (Waseda University) | Furui, Kenji (Waseda University) | Mandai, Shusaku (Mitsubishi Chemical Corporation) | Ishihara, Chizuko (Mitsubishi Chemical Corporation) | Hirano, Yasuhiro (Mitsubishi Chemical Corporation) | Taniguchi, Ryosuke (Mitsubishi Chemical Corporation, Now with Soarus L.L.C.)
It has been reported that hydraulic fracturing treatments with smaller cluster spacing and larger fracturing fluids volumes yield better production performance in Permian Basin, Bakken, and Eagle Ford. Degradable diverting agents can play an important role as temporary plugging materials for multiple, tightly-spaced fracturing operations. However, applications of degradable diverting agents are often limited to moderate to high reservoir temperatures. In this study, a new degradable diverting agent is developed for use in low temperature reservoir applications.
Butane-diol vinyl alcohol co-polymer (BVOH) which has controllable water solubility is evaluated as diverting agents for hydraulic fracturing treatments. Using a high pressure-high temperature filtration apparatus, filtration properties of BVOH diverting agents are measured for various powder-to-pellet ratios under a range of temperature conditions. Filter media with 1 to 3 mm width slots, that simulate fracture openings, are used for the filtration test. The filtrate properties are evaluated based on spurt losses and filtration coefficients for quantitative evaluation. An analytical diverting agent model that considers swelling of the polymer in water is also developed for evaluating the filtration process of multimodal particles.
The experimental results presented in this work indicate that the degradable BVOH materials can be used as effective plugging agents for fracture-like narrow slits. Based on spurt losses and leakoff coefficients obtained under different powder-to-pellet ratios and temperature conditions, the performance of the diverting agents is quantitatively evaluated. The optimum powder-to-pellet ratio for BVOH materials are determined to be 80 to 20. The experimental results also reveal that the degree of BVOH crystallinity provides a dominant effect on the solubility of BVOH powder. The test results also indicate that the diverting agent plug properties started degrading under the temperature greater than 140°F as designed. The BVOH diverting agent developed in this work provides effective diversion effects under low to moderate temperature conditions (e.g., 80 to 100°F). The analytical plugging and bridging model developed in this work, which takes into account swelling properties of the polymer, show very good matches to the experimental results.
The degradable diverting agent developed for low temperature applications improve operational efficiency and economics of multistage hydraulic fracturing treatments in shallow reservoirs and operations where immediate fracturing fluid flowback is required. The plugging and bridging model with bimodal particle system developed in this study helps stimulation engineers select and optimize diverting agent material types, particle size distribution, and diverting agent concentration for various well, stimulation, and reservoir conditions.