Journal of Petroleum Technology最新文献

{"title":"Polymer-Assisted WAG Injection Improves CO2 Flow Properties in Porous Media","authors":"C. Carpenter","doi":"10.2118/0624-0083-jpt","DOIUrl":"https://doi.org/10.2118/0624-0083-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 215024, “Polymer-Assisted Water-Alternating-Gas for Improving CO2 Flow Properties in Porous Media,” by Mohsen M. Yegane, SPE, Delft University of Technology and the Dutch Polymer Institute; Thijs van Wieren, SPE, Delft University of Technology; and Ali Fadili, Shell, et al. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 CO2 flow in porous media is vital for both enhanced oil recovery and underground carbon storage. For improving CO2 mobility control and improved reservoir sweep efficiency, water-alternating-gas (WAG) injection often has been applied. The effectiveness of WAG diminishes, however, because of the presence of microscale reservoir heterogeneity that results in an early breakthrough of gas. In the complete paper, the authors propose polymer-assisted WAG (PA-WAG) as an alternative method to reduce gas mobility and the mobility of the aqueous phase, consequently improving the performance of WAG. In this method, high-molecular-weight water-soluble polymers are added to the water slug.\u0000 \u0000 \u0000 \u0000 Recently, PA-WAG has received attention as a method to mitigate early gas breakthrough and gravity segregation during WAG injection. However, the flow mechanisms in PA-WAG injection in porous media remain poorly understood. In particular, no experimental study exists to the authors’ knowledge that demonstrates in-situ visualization and discusses how PA-WAG can improve the gravity override and early gas breakthrough of WAG. The objective of this study is to demonstrate experimentally the feasibility of PA-WAG by conducting a series of X-ray computed tomography (CT) -aided coreflood experiments. To this end, coreflood experiments in Bentheimer cores using different injection schemes (CO2 and polymer injection, WAG injection, and PA-WAG injection) were conducted. The aim of CT scanning during the coreflood experiments was to map the phase saturations at different times of injection. Using dual-energy CT scanning, a reduction in gravity override could be visualized, and the CO2 breakthrough was delayed when PA-WAG was used.\u0000 \u0000 \u0000 \u0000 Table 1 of the complete paper presents the various chemical components that were used in this study. The coreflood experiments were performed using Bentheimer sandstone cores. Bentheimer cores have high permeabilities and a homogeneous mineralogy. The porosity of the core samples was measured using CT scanning.\u0000 To introduce the aqueous phases into the core, a dual-cylinder pump was used. The core, core holder, and heating sleeve were placed in a fixed horizontal position on the CT bench because vertical scanning led to undesirable artifacts and yielded no meaningful insights. Fraction-collector sampling was used to collect effluents at the outlet at various time intervals. CO2 was injected into the system by a mass-flow controller sourced from a dedicated CO2 supply. The pump indirectly introduced both the oleic phase during prima","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141276233","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A Grand Challenge Update on Improved Recovery From Tight/Shale Reservoirs","authors":"Gideon Dordzie, M. Balhoff","doi":"10.2118/0624-0038-jpt","DOIUrl":"https://doi.org/10.2118/0624-0038-jpt","url":null,"abstract":"\u0000 \u0000 This is the third of a series of six articles on SPE’s Grand Challenges in Energy, formulated as the output of a 2023 workshop held by the SPE Research and Development Technical Section in Austin, Texas.\u0000 Described in a JPT article last year, each of the challenges will be discussed separately in this series: geothermal energy; net-zero operations; improving recovery from tight/shale resources; carbon capture, storage, and utilization; digital transformation; and education and advocacy.\u0000 \u0000 \u0000 \u0000 The exploration and extraction of hydrocarbons from tight or shale formations have revolutionized the global energy landscape, unlocking vast oil and gas reserves previously considered inaccessible. According to estimates, substantial oil production has been reported for various tight plays in the US in 2024 (Fig. 1).\u0000 However, the production process in tight or shale formations is not without its own set of challenges ranging from technological hurdles to environmental concerns. Therefore, understanding the current outlook is essential for stakeholders to navigate the complex terrain.\u0000 To address the significant issues outlined by SPE in July 2023 (Halsey et al. 2023), this article intends to explore the complexities of hydrocarbon extraction from tight and shale reservoirs.\u0000 \u0000 \u0000 \u0000 First, we present a succinct description of tight or shale formations. Tight or shale oil and gas are hydrocarbons found in oil-bearing mudstone, and shale gas is produced from gas shale or associated with tight oil (Boak and Kleinberg 2020). Tight unconventional formations are characterized by the presence of fine-grained sedimentary rocks that are high in organic matter, such as shale, where hydrocarbons are firmly embedded within the rock matrix.\u0000 \u0000 \u0000 \u0000 The Existence of Complex Geometry.\u0000 Tight and shale formations are known for their complex geological structures, which can make it difficult to predict the distribution and behavior of hydrocarbons within the reservoir. Additionally, shale formations can exhibit significant variability in their thickness, composition, and the occurrence of natural fractures. Hence, it is crucial to understand and navigate the intricate geology of unconventional shale formations to achieve successful shale oil production (Jiang et al. 2016).\u0000 Ultralow Reservoir Permeability.\u0000 The low permeability of tight formations restricts the flow of hydrocarbons, necessitating techniques such as hydraulic fracturing to create artificial pathways for extraction. However, the effective stimulation of fractures requires the use of cutting-edge drilling and extraction methods, such as multistage hydraulic fracturing (fracking) and horizontal drilling, which in turn require precise engineering and a thorough understanding of reservoir characteristics (Pokalai et al. 2015).\u0000","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141232023","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Nanoparticle-Based Fluids Reverse Long-Term Hydrocarbon Decline","authors":"C. Carpenter","doi":"10.2118/0624-0064-jpt","DOIUrl":"https://doi.org/10.2118/0624-0064-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 3848516, “Tailored Metal Oxide Nanoparticles-Based Fluids in Acid Restimulation Treatments Reverse Long-Term Hydrocarbon Decline: A Pilot Study in Wolfcamp A Formation,” by Panagiotis Dalamarinis, SPE, DG Petro Oil and Gas, and Amr Radwan and Raja Ramanathan, TenEx Technologies, et al. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 Multifractured horizontal wells suffer from high hydrocarbon decline and water cuts after initial flowback. This behavior is in part because of near- and far-field-fracture conductivity damage. Refracturing operations (acid or proppant) can mitigate these problems, yielding a good cleanout performance and stable oil-recovery trends. The complete paper details a successful pilot to improve long-term well performance using acid stimulation aided by a pioneering tailored metal oxide (TMO) nanoparticle-based fluids in the Wolfcamp A formation.\u0000 \u0000 \u0000 \u0000 The reason for replacing normal surfactants with the TMO nanofluid was its ability to create bonds between the fracture phase and rock matrix, overcome the problems normal surfactants demonstrate, and provide long-term production maintenance. The nanofluid is made of proprietary blends of metal oxide nanoparticles and other additives to improve stability and compatibility under harsh reservoir conditions.\u0000 The nanofluid was engineered to be effective under a wide range of lithologies, salinities, crude oils, temperatures, and pH changes. The nanofluid is a nontoxic, nonhazardous, water-based fluid containing one or multiple types of metal oxide nanoparticles with stabilizing chemistry. The size of the nanoparticles can be as low as 3 nm. The nanofluid works by a mechanism called structural disjoining pressure, or “uplift pressure.” The nanoparticles form a wedge underneath the organic matter and allow it to disconnect from the surface against different crude-oil types that may overcome normal surfactant limitations by replacing conventional chemical-based solutions. The TMO nanofluid has shown a trend of alleviating the decline rate in treated wells that is believed to be linked to the long-term wettability alteration mechanism. The effectiveness of the treatment improves when the nanofluids can be tailored to specific crude oils and rock mineralogy.\u0000 \u0000 \u0000 \u0000 Two groups of wells were used in this study, one in Reeves County (three wells) and one in Culberson County (four wells). Each group of wells had different reservoir and production characteristics. For each of the wells, water and oil samples were collected, analyzed, and, based on this data, nanofluids were used in one well of each group instead of normal surfactants.\u0000 The artificial lift systems used after the acid restimulation of all wells presented in this study were electrical submersible pumps (ESPs). After the initial flowback (approximately 2 weeks), when the targeted production rates for each well were achieved, th","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141279215","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Far-Field Diverters Protect Parent-Well Production in Unconventional Wells","authors":"C. Carpenter","doi":"10.2118/0624-0069-jpt","DOIUrl":"https://doi.org/10.2118/0624-0069-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 217813, “Protecting Parent-Well Production Using Far-Field Diverters in Unconventional Wells,” by Foluke O. Ajisafe, SPE, Liberty Energy, and Hank Porter, SPE, and Sunny Kothare, Lime Rock Resources, et al. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 The effect of fracture-driven interaction (FDI) is an increasing concern in mature developed unconventional plays in the US. In this study, parent-well production performance after infill-well stimulation is evaluated to understand the effectiveness of a far-field diverter in mitigating FDIs. Studies to determine whether FDIs result in a negative or positive effect have concluded that the effect varies from basin to basin. In this project, the purpose of pumping the far-field diverter is to mitigate wellbore sanding and production loss in existing parent wells.\u0000 \u0000 \u0000 \u0000 The operator in this study is active in the Bakken and Three Forks formation in the Williston Basin and had experienced the negative effect of FDIs. These can occur because of close well spacing and large fluid and proppant volumes and can be exacerbated by reservoir pressure depletion caused by production. In the project described in the complete paper, pressure depletion is the main driver for fracture hits to the parent wells. Most of the parent wells have been in production for years before infill-well drilling and completion. The main goal is to maximize production of parent and infill wells and avoid sanding the parent well by decreasing the frequency and severity of fracture hits to parent wells. To combat this issue, operators have tried several solutions, such as optimized well spacing and treatment designs, repressurization, and even refracturing, with mixed results. A cost-effective solution with simpler operational logistics, the use of a far-field diverter was considered to create more complexity and reduce the occurrence of extended fracture geometry toward the depleted zone or region. The far-field diverter pill is a mixture of materials transported to the tip of the fracture, where they bridge and create a low-permeability plug for fracture geometry control to mitigate FDIs.\u0000 The complete paper provides a history of the operator’s experience with the use of far-field diverters.\u0000 \u0000 \u0000 \u0000 Since 2019, multiple infill (child) wells have been completed, and far-field diverters implemented, to mitigate fracture hits to offset parent wells. Extensive work was completed in eight different well pads (Pad A through Pad H) across three different counties, Dunn, Mountrail, and McKenzie. The far-field diverter pill was pumped in 25 horizontal wells landed in both the Middle Bakken and Three Forks formations. The main objective of this study was to investigate the production effect on parent wells after the use of far-field diverter on the infill wells.\u0000","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141277396","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Fracture Stimulation Increases Production in Challenging North African Completions","authors":"C. Carpenter","doi":"10.2118/0624-0075-jpt","DOIUrl":"https://doi.org/10.2118/0624-0075-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 215705, “Increasing Production and Reserves Through Fracture Stimulation in Challenging, Multizone, Vertical Well Completions,” by Andrew Boucher, SPE, Josef R. Shaoul, SPE, and Inna Tkachuk, SPE, Fenix Consulting Delft, et al. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 The complete paper presents a case study of a North African oil field scattered with wells that did not initially require fracture stimulation for economic production but now could benefit from hydraulic fracturing. Many of these wells are producing from multiple perforated intervals through completions with production tubing that were not designed for fracturing and cannot be worked over. The field is producing from two Ordovician sands, one with a higher permeability (5 md) and one with a much lower permeability (0.5 md). Significant benefit was achieved by fracture stimulating one or both intervals in two wells, despite completion and operational limitations.\u0000 \u0000 \u0000 \u0000 For the field of interest, the operator drilled and completed two exploration wells on its concession in 2015, targeting multiple reservoir layers. Both wells successfully flowed hydrocarbons from the Ordovician Atchane and Jeffara intervals.\u0000 Initial petrophysical analysis results indicated that Well 2 had more net height and better reservoir quality than Well 1 and that the Atchane reservoir is of better quality than the Jeffara reservoir because it contains approximately 80% of the permeability thickness (kh). Atchane holds more of the total reserves.\u0000 A field-development plan and reservoir model were prepared. The reservoir model indicated that the two drilled wells were located adequately to allow good recovery of the field reserves, so these wells were temporarily suspended by loading with heavy calcium bromide (CaBr2) brine while tie-in to surface production facilities could be completed.\u0000 The reservoir contains very light, volatile oil with a high gas/oil ratio. The reservoir was initially overpressured, with an initial reservoir pressure of 8,800 psi, which is a reservoir pressure gradient of 0.725 psi/ft. However, significant and uneven depletion was experienced before any fracturing operations.\u0000 \u0000 \u0000 \u0000 Once the two wells were tied in and brought back online, production was lower than expected. One or more of the open intervals in both wells were identified as being damaged or poorly connected to the wellbore. Hydraulic fracturing was identified as a technique that could improve well productivity.\u0000 The operator did not have significant experience with fracturing, so a qualified team was assembled to evaluate the situation while considering strict regulatory criteria.\u0000 First, the current completions could not be changed. In general, both wells had two long perforation intervals producing in a large, cemented liner with an upper completion consisting of small tubing and at least one packer. Standard approach","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141278058","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A New Magazine for a New Era: JPT and the Global Petroleum Landscape in 1949","authors":"C. Carpenter","doi":"10.2118/0624-0016-jpt","DOIUrl":"https://doi.org/10.2118/0624-0016-jpt","url":null,"abstract":"\u0000 \u0000 In January of 1949, a new publication jostled for its place amidst the sudden abundance of titles devoted to technical professional associations. The publishing marketplace, like every other, was evolving daily in a world that hoped technological leaps never before imagined would not only leave behind recent global tragedy but also make its recurrence impossible.\u0000 Volume 1, Number 1 of the Journal of Petroleum Technology—then the official publication of the Petroleum Branch of the AIME—wore an efficient but striking clover-green-and-cream cover, its 92 pages containing sections devoted to editorials, AIME-wide developments, upcoming meetings, feature articles, and technical papers (including, famously, a paper on a new technique that author J.B. Clark dubbed “Hydrafrac”).\u0000 The teaser text for Branch Chair I.W. Alcorn’s inaugural Editorial Comment framed the new magazine as “the kingpin of a broadened branch program and a real force in strengthening the profession if members will but use it to carry opinion and incite action.”\u0000 As JPT celebrates its 75th anniversary, a brief review of the global petroleum landscape during its first year of publication casts new light on the magazine itself—and the lofty expectations attached to the industry it supported.\u0000 \u0000 \u0000 \u0000 Before a rebuilt world could be fueled by petroleum, the conditions of its peace had to be defined, and thus its eyes were on Europe in 1949. The Marshall Plan had enabled a major uptick in European oil production, such that Western Europe produced just over 11 million bbl in 1949 in countries such as the Netherlands, France, and the just-established Federal Republic of Germany.\u0000 More than a decade distant were offshore discoveries that would revolutionize Europe’s role in global petroleum, but at the time of JPT’s launch, Europe remained a potential trigger for a war that all were desperate to avoid—indeed, in the UK, wartime rationing had not yet ended, and in the year of JPT’s debut, the petrol ration was increased to allow a generous 180 miles per month.\u0000 While the globe remained in upheaval as anticolonial rebellions were launched—mostly against European empires—and attempts were made to fill power vacuums, the showdown between the West and the Soviet Bloc had solidified into a dangerous reality that cast a shadow over every nation. The North Atlantic Treaty Organization was ratified in April, and the following month, the blockade of Berlin came to an end in what was seen as a major symbolic victory for the West, evident proof that its reliance upon technology could safeguard humanity.\u0000","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141277616","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Hydraulic Fracturing Optimizes Extraction of Reservoir Initially Considered Secondary","authors":"C. Carpenter","doi":"10.2118/0624-0072-jpt","DOIUrl":"https://doi.org/10.2118/0624-0072-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 213110, “Hydrocarbon Production Enhancement on the Apaika-Nenke Field by Applying Hydraulic Fracturing as a Tool To Optimize the Extraction of Reservoir M2 Considered Initially as a Secondary Target,” by Franck Salazar and Nestor D. Vasconez, Schlumberger, and Christopher J. Mayorga, SPE, Petroecuador, et al. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 As a result of reservoir conditions in Ecuador’s Apaika-Nenke field, a hydraulic fracturing pilot project was executed with the aim of maximizing production. After an analysis of the laminated reservoirs, a technique was implemented that generates higher fracture conductivity to reduce the drawdown during production and improve the connection through the laminations. The successful implementation of channel fracturing led to this technique becoming the preferred completion method in the field for wells requiring stimulation.\u0000 \u0000 \u0000 \u0000 The Apaika-Nenke structure is in Orellana Province of the Amazonian region inside of Block 31. Initial production tests in Well Apaika-1X showed an oil rate of 1,201 BOPD from the M1 reservoir and 653 BOPD from the M2 reservoir. In the Nenke-1X well, the oil rate was 1,600 BOPD from M1 and 328 BOPD from M2. Because higher oil rates were obtained from M1, the development phase that began in 2013 targeted the M1 reservoir as its primary objective. However, Well Apaika-A14 produced 150 BOPD only from the M2 reservoir. The maximum production from the oil field was 22,107 BOPD from M1 and 262 BOPD from M2 in April 2016 but has declined to 2,692 BOPD from M1 and 657 BOPD from M2.\u0000 M1 is the main producing reservoir in Apaika-Nenke, which produces using conventional techniques. M2, however, was treated as a secondary target with low and difficult production levels; production from Well Apaika-A14 required hydraulic fracturing to reach commercial levels. This well raised the possibility of hydraulic fracturing in the M2 reservoir, opening doors for targets previously considered secondary.\u0000 \u0000 \u0000 \u0000 M2 is a highly shale-laminated sandstone with a glauconitic sequence. Shale/sandstone intercalations are found within the pay zone, a key feature for hydraulic fracturing.\u0000 Well Apaika-A14 in M2 produces 14.9 °API oil with salinity levels on the order of 2,000 ppm chloride, while Well Nenke-B1 produces 16.3 °API oil and salinity levels of 9,000-ppm chloride. Well Nenke-B2 produces 14.7 °API oil with salinity levels of 5,600-ppm chloride. This information indicates that the oil producing from M2 is heavy. The oil viscosity is 104 cp at 194°F.\u0000 A pore/volume/temperature analysis shows that the oil in the M2 reservoir is undersaturated and produces above the reported bubblepoint of 320 psi. The original reservoir pressure was 2,760 psi before initiation of hydraulic fracturing.\u0000","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141280509","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Working To Solve the Permian Gas Conundrum","authors":"Blake Wright","doi":"10.2118/0624-0032-jpt","DOIUrl":"https://doi.org/10.2118/0624-0032-jpt","url":null,"abstract":"Reflecting on oilfield history as a whole, it wasn’t all that long ago that natural gas was treated more like a nuisance than a commodity, either an undesirable byproduct of an oil discovery or a letdown when it was encountered in a well instead of the targeted black gold.\u0000 It can complicate things when an operator is drilling for oil, especially during periods like now when crude prices are robust, but gas prices aren’t. Additionally, when oil is discovered, it often comes with associated natural gas. When producers turn the taps to get that oil into sales lines, the gas can be problematic if the limited takeaway capacity for transporting it is already stretched.\u0000 This is the current situation for many operators in the prolific Permian Basin of west Texas and south-east New Mexico.\u0000 Infrastructure constraints to ship natural gas out of the Permian combined with high storage levels due to a relatively mild winter are wreaking natural gas pricing in the region. Natural gas prices at the WAHA hub located near Fort Stockton, Texas, were below zero—negative $4.60/MMBtu as recently early May.\u0000 Not only did that mean that produced gas in the region was basically free, but the negative price also meant producers trying to move gas out of the region would have to pay someone extra to do it. That’s not good business. Of course, anyone looking to chase that offer would find no pipeline capacity to move the product.\u0000 The US Energy Information Administration (EIA) said in December 2023 that production of associated natural gas has nearly tripled since 2018 in the three top-producing tight oil plays in the Permian region. Associated natural gas from the Wolfcamp, Spraberry, and Bone Spring plays averaged a combined 13.7 Bcf/D in the first 7 months of 2023, up from an average of 4.7 Bcf/D in 2018, according to data from Enverus. Associated natural gas production has grown due to increases in both crude oil production and the volume of natural gas per barrel of oil that a well produces, the gas/oil ratio, among the oil wells in these three plays.\u0000 The cavalry is on the horizon, however. A handful of high-capacity Permian natural gas export projects are moving through various stages of development and aim be operational over the next few years.\u0000 First up is the giant Matterhorn Express pipeline, which will move gas from west Texas to Katy, Texas (just west of Houston) and connect with other pipelines. The project, led by WhiteWater Midstream, EnLink Midstream, Devon Energy, and MPLX, is roughly 80% complete and should come online in the second half of this year.\u0000 Energy Transfer’s Warrior pipeline is loading up on transport commitments and will move gas from the Permian to the Gulf Coast. This system is on track for a potential late-2024 final investment decision (FID).","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141282029","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Limited-Entry-Liner Well Stimulated Effectively With a Viscoelastic Diverter-Acid System","authors":"C. Carpenter","doi":"10.2118/0624-0058-jpt","DOIUrl":"https://doi.org/10.2118/0624-0058-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 213785, “Effective Stimulation of a Limited-Entry-Liner Well Using a Leading Viscoelastic Diverter-Acid System,” by Timothy I. Morrow, SPE, and Ahmed M. Fawzy, ADNOC, and Abraham Ryan, SPE, SLB, et al. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 A horizontal water-injection well with a limited-entry-liner (LEL) completion in an onshore Middle East carbonate reservoir was stimulated with hydrochloric acid (HCl) using a large volume of a viscoelastic diverter-acid (VEDA) fluid system ahead of the main acid stage. The VEDA stage was needed to deliver sufficient acid volumes to the toe of the well, resulting in a significant increase to the injectivity index and more-even distribution of injected water across the horizontal drain.\u0000 \u0000 \u0000 \u0000 The LEL is a lower completion type designed for openhole wells. It consists of an array of small, unevenly spaced holes placed along a string of blank pipes. Swell packers typically are placed along the LEL completion to divide the lateral into compartments. The size of the LEL holes usually is in the range of 3–6 mm. The LEL completion provides the capability to perform acid stimulation by bullheading at high pumping rates, and the distribution of the holes serves to provide a type of mechanical diversion of the stimulation fluids. A simplified schematic of the LEL concept is shown in Fig. 1. The properties of the LEL used in this study include the following:\u0000 - Hole spacing broadly is within the design range of 40–60 ft\u0000 - Average compartment length is within the design range of 500–1,000 ft\u0000 - A significant permeability contrast exists between the heel (Aones 1 and 2) and the toe (Aones 4 and 5).\u0000 The total injection interval for this well is 4,075 ft. Because of the large permeability contrast between the heel and toe, however, it is possible that a bullhead acid stimulation may result in a relatively small volume of acid entering the toe compartments.\u0000 \u0000 \u0000 \u0000 The acid stimulation for this well consisted of 42 gal/ft of 15% HCl to be pumped at the maximum allowable rate. Acid stimulation treatment modeling was performed for the following three scenarios:\u0000 - A hypothetical scenario of 15% HCl pumped into an openhole completion\u0000 - The baseline scenario of 15% HCl without any VEDA stages pumped into the LEL\u0000 - An alternate scenario in which a VEDA stage is added to the beginning of the acid package and pumped into the LEL\u0000 The purpose of modeling the hypothetical scenario was to illustrate the mechanical diversion provided by the LEL.\u0000 For a hypothetical openhole completion, a bullhead acid stimulation at maximum allowable pumping rate was predicted to place very little acid into Zone 5 at the toe of the well. Conversely, the higher-permeability heel Zones 1 and 2 would take most of the acid (approximately 80%), with Zones 3 and 4 receiving just 20%. By comparing the simulation results between Scenario 1 and Scenario","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141281950","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Underbalanced Coiled Tubing Approach Targets Natural Fractures in Tight Sandstones","authors":"C. Carpenter","doi":"10.2118/0624-0046-jpt","DOIUrl":"https://doi.org/10.2118/0624-0046-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 23188, “Underbalanced Coiled Tubing Technology in Tight Sandstones: A Success Story by Integrating Petrophysics, Geophysics, Flow Data, and Pressure-Transient Analysis To Target Natural Fractures,” by Ali R. Al-Nasser, Ali J. Al-Solial, SPE, and Abdulrahman Y. Abushal, SPE, Saudi Aramco, et al. The paper has not been peer reviewed. Copyright 2024 International Petroleum Technology Conference.\u0000 \u0000 \u0000 \u0000 The complete paper describes the use of underbalanced coiled tubing drilling (UBCTD) technology in tight sandstones, using an integrative approach that incorporates petrophysical, geophysical, and reservoir engineering data. The primary objective is to distinguish between high matrix permeability and natural fractures, focusing on a localized high-permeability region subject to detailed analysis before implementing a UBCTD operation. The integrative methodology examines various data sets, including log data, production-logging-tool (PLT) results, seismic interpretation, well rates, and pressure transient analysis (PTA).\u0000 \u0000 \u0000 \u0000 The success of any well is heavily contingent on strategic placement, a critical factor magnified in the context of UBCTD. Misplacing a well in UBCTD can have catastrophic consequences for productivity and severability. While targeting areas of high flow capacity (kh) is desirable, steering clear of unstable zones and materials prone to creep is equally crucial. UBCTD emphasizes the need for meticulous analysis and a profound understanding of the development area.\u0000 UBCTD wells are crafted as producers with the sole purpose of efficient production rather than extensive evaluation. Fracture networks, generally perceived as a risk in conventional drilling, are less problematic in UBCTD. Intentionally targeting zones of loss circulation becomes a viable approach to enhance productivity. This analytical focus on targeting fractures for increased productivity can be extrapolated to target high-permeability streaks and optimize deposition in UBCTD wells.\u0000 The proposed workflow for similar projects entails a thorough investigation leveraging multiple data sources to assess various reservoir parameters. The key components include production rates, porosity and permeability evaluations from logs and cores, kh determination through PTA, and examination of fracture responses through image logs. The authors stress that PTA is not merely a criterion for UBCTD but is a valuable reservoir characterization tool.\u0000 Analyzing scenarios with high flow rates, high porosity or permeability, and moderate kh—or, conversely, high flow rates, moderate porosity or permeability, and exceptionally high kh—can be relatively straightforward. However, complications arise in scenarios with poor production rates and high kh coupled with fractures visible in image logs, indicating inadequate vertical lift performance. Another challenging scenario involves poor pro","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141229056","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}