International Petroleum Research Articles

Material Selection and Corrosion Rate Analyzed for CO2 Injection Well

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 21818, “Material Selection and Corrosion-Rate Analysis for CO2 Injection Well: A Case Study of K1 Field CO2 Sequestration Project,” by Mohd A. Abu Bakar, Wan Amni Wan Mohamad, and M. Wahidullah M. Wahi, Petronas, et al. The paper has not been peer reviewed. Copyright 2021 International Petroleum Technology Conference. Reproduced by permission. _ Typical materials used for CO2 injector wells are either corrosion-resistant alloys (CRA) or epoxy-lined tubulars. The most widely adopted CRA material is 25Cr, which features a high well-application cost. Application of materials other than 25Cr for CO2 injector wells are uncommon but may be fit for purpose. The complete paper describes material-selection methodology and corrosion studies performed in the K1 field CO2 sequestration project using materials other than 25Cr in an effort to optimize well costs and improve overall project economics without jeopardizing CO2 injector-well integrity. Introduction K1 field is in the Sarawak Basin at a water depth of 453 ft. It was discovered by an exploration well in 1972 and appraised by a dedicated well in 1992. The field features a gas column of 324 ft from the free water level at 4,990 ft true vertical depth subsea. Gas initially in place for this field is estimated at approximately 2,800 Bscf. CO2 storage screening studies had identified an opportunity to use the K1 field as a storage site. The source of CO2 gas is a nearby field, from which separated CO2 gas will be transported through a 130-km pipeline to the K1 field’s new injection-wellhead platform. The current plan is to inject and store the CO2 inside one of the depleted carbonate reservoirs until an increase in reservoir pressure to the initial pressure of 3,440 psi is observed. The reservoir temperature is approximately 120°C. Injection-Fluid Composition and Presence of Water Injection fluid contains a high mol% of CO2, methane, and other impurities such as nitrogen and hydrogen sulfide (H2S) gases. Injection fluid will be injected above the CO2 supercritical condition. Based on the injection fluid’s composition, CO2 will be the main source of corrosion in the presence of water when exposed to unprotected tubulars in the wells. The presence of H2S denotes the effect of stress corrosion cracking (SCC) and sulfide stress cracking (SSC), which must be considered in selecting tubing material for the injector wells. A small percentage of water (approximately 0.0086 mol%) also exists in the injection fluid. This will be detrimental to the injection wells in terms of corrosion if it is in the aqueous phase. To study this, the well’s shut-in and injection pressures and temperatures were plotted against the water-phase diagram. During these conditions, water in the injection fluid exists as vapor phase. Considering the possible risks of a higher percentage of water in the injection fluid, a more- conservative approach was taken in the selection of tubing material for the injector wells.

A Novel 2.5D Deep Network Inversion of Gravity Anomalies to Estimate Basement Topography

Summary A novel 2.5D intelligent gravity inversion technique has been developed to estimate basement topography. A deep neural network (DNN) is used to address the fundamental nonuniqueness and nonlinearity flaws of geophysical inversions. The training data set is simulated by adopting a new technique. Using parallel computing algorithms, thousands of forward models of the subsurface with their corresponding gravity anomalies are simulated in a few minutes. Each forward model randomly selects the values of its parameter from a set of predefined ranges based on the geological and structural characteristics of the target area. A DNN model is trained based on the simulated data set to conduct the nonlinear inverse mapping of gravity anomalies to basement topography in offshore Abu Dhabi, United Arab Emirates. The performance of the trained model is assessed by making predictions on noise-free and noise-contaminated gravity data. Eventually, the DNN inversion model is used to estimate the basement topography using pseudogravity anomalies. The results show the depth of the basement is between 7.4 km and 9.3 km over the Ghasha hydrocarbon reservoir. This paper is the 2.5D and improved version of the research (SPE-211800-MS) recently presented and published in the Abu Dhabi International Petroleum Exhibition & Conference (31 October–3 November 2022) proceedings.

How transnational rules can contribute to the improvement of the Brazilian regulatory system for unitization—an analysis under the transnational legal order perspective

Abstract Unitization is the most effective method to avoid irrational, wasteful and environmentally unsustainable production of oil and natural gas. Therefore, it is important to notice that unitization is a complex practice. It is effective for the equitable production division of a deposit shared by different owners. However, compulsory membership can result in costly negotiation and make exploration and production projects less attractive. In the pre-salt, the most productive Brazilian oil province, unitization processes are common and even more complex due to the following factors: (i) there are three different tax regimes in the pre-salt polygon; (ii) when the reservoir is shared with an area not granted yet (referred to as an open area), the Brazilian regulation establishes that the unitization process must be carried out with the public company, Pré-sal Petróleo S.A., representing the Government; (iii) moreover, due to the high productivity of the pre-salt layer, the financial values involved in this process are substantial, even with a participation of less than 1 per cent in the shared reservoir. Brazil established a robust regulation on unitization in 2013, which was amended in 2017 and, again, in 2020. This demonstrates that the regulatory improvement process, in the search for a more efficient regulation—that balances the attraction of investments and protection of the public interest—is continuous. This article proposes that in this process of regulatory improvement, good international petroleum industry practices (good practices), contractual models drawn up by industry associations and codes of conduct shall be used as a reference. These non-state rules, which are the result of self-regulation by the upstream sector of the oil industry, will be considered in this article as transnational rules, following the approach of Halliday and Shaffer, who propose the existence of a transnational legal order.

Efforts Lead to Formulation of High-Performance ASP

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 22729, “ASP Formulation Development Journey: Optimization, Validation, and Quality Control for Mangala Field,” by Nitish Koduru, Dhruva Prasad, SPE, and Amitabh Pandey, SPE, Cairn Oil and Gas. The paper has not been peer reviewed. Copyright 2023 International Petroleum Technology Conference. Reproduced by permission. _ Mangala is a large low-salinity, high-quality fluvial oil field in India with stock-tank oil initially in place (STOIIP) of more than 1 billion bbl of waxy and moderately viscous crude. Aqueous-based chemical enhanced oil recovery (EOR) has been identified as the most suitable technique to improve recovery over waterflooding. The objective of the complete paper is to describe alkaline/surfactant/polymer (ASP) formulation development for Mangala, which involved more than 30 corefloods at the time of writing, with formulation design changing over time. Field Background The Mangala field has been regarded as an excellent chemical EOR candidate since its discovery in 2004. The main reservoir unit is divided into the Lower and Upper Fatehgarh formations. These units are subdivided into five reservoir units, FM1 to FM5 from top to bottom. Mangala contains waxy sweet crude oil with gravity ranging from 20 °API near the oil/water contact to 28 °API in the oil column. The crude has in-situ viscosity of 9–17 cp. The crude has good napthenic acid content and reacts with alkali to produce in-situ soap. Immediately after the field’s appraisal stage, work to identify the most suitable EOR process began. First, a polymerflooding pilot was conducted during 2011–12. The encouraging results led to full-field polymerflooding implementation in November 2014. The ASP pilot performed well; incremental oil recovery over polymerflooding was estimated to be in the range of 20–25% of the pilot STOIIP. The initial development plan involved implementing a hot waterflooding production startup to maintain reservoir pressure and effective sweep. The Upper Fatehgarh FM1 and FM2 units were developed with inverted nine-spot patterns, while the more-homogeneous lower Fatehgarh (FM3 and FM4) were developed with downdip injectors and updip horizontal producers. The Mangala field began producing under a hot waterflood in 2009, with the injected water heated to approximately 80–85°C to avoid wax deposition. Injection was started within a few months of first production. At the time of writing, the field is under polymerflooding, with results largely in line with expectations. The field, which has already produced approximately 37% of the STOIIP, is on a declining production trend, and large-scale ASP flooding is being considered as the next development initiative to arrest production decline and increase overall recovery. The complete paper discusses EOR screening studies; ASP formulations, including the initial formulation; the method adopted for selection of chemical suppliers for the pilot test; optimization of ASP formulations tested in the pilot; validation of the developed formulation to other layers of the field; and planned quality-control processes to be used during procurement of chemicals for larger applications of ASP floods in the field. This synopsis concentrates on the last three of these factors, rather than the formulations considered, which, in addition to the initial formulation, included the following: - Formula 2: ASP formulation with a sacrificial surfactant - Formula 3: ASP formulation with a single surfactant - Formula 4: Formulation with a highly hydrophilic, large-hydrophobe surfactant

Intermediate String Design Enhances Intelligent Deepwater Completions

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 22087, “One Innovative Intelligent Completion Intermediate String Design for Deepwater Gas-Well Completions: The Installation Case Study From L Gas Field, China,” by Shu Jie Liu, Yi Huang, and Wen Bo Meng, CNOOC, et al. The paper has not been peer reviewed. Copyright 2022 International Petroleum Technology Conference. Reproduced by permission. _ An intelligent completion design was installed in two wells in China’s L field deepwater project. Both wells have dual-zone stack-pack sand-control lower completions. To handle critical well-control concerns and enable production from each zone, an intermediate string was installed to isolate the reservoir in each zone temporarily. While the complete paper details both the completion string design and its field installation, this synopsis concentrates on the former aspect of the project. This practice will benefit upcoming deepwater well-completion designs, especially for high-pressure/high-temperature gas-field-development projects. Introduction The L field is a deepwater gas field in the Qiong Dongnan Basin with a water depth from 1200 to 1500 m in the South China Sea. The field was discovered in 2014; development launched in early 2018 with a plan for 11 development wells. The target zone of this field is over 3000 m true vertical depth with a widely distributed thin layer of sand deposition. The target zone has a normal pressure gradient of 1.2 and temperature that reaches 93°C. The 11 wells planned included six horizontal and five deviated wells. The openhole drilling of the first well began in April 2020, and the cased-hole intelligent completion of the last well was finished in March 2021. The openhole gravel packs in the first three wells were completed as the first batch. One cased-hole single-zone gravel pack was completed as the fourth well because it sat on the same flank of the reservoir as the first batch of three openhole wells. After that, a floating rig was mobilized on the other flank to complete the remaining three openhole wells. Then, the remaining two cased-hole single-zone gravel-pack completions followed. The most challenging completion, a dual-zone stack-pack intelligent completion, was performed in the last two wells in February and March 2021. A dedicated project manager and team were assigned throughout project execution. The project-management team strictly adhered to the operator’s completion project-management system; managed the interfaces, risks, and schedules through a scientific approach; and provided technical and troubleshooting support in a timely manner. All 11 wells were completed by April 2021, including the two intelligent well completions. The entire field was brought into production by mid-2021. Well-Completion Design Challenges Because of the unconsolidated sandstone present in the field, all 11 wells required a proper sand-control lower completion to eliminate the issue of sand production. However, the geologic conditions of widely distributed sand deposition and a thinly layered gas reservoir required the operator to use three different types of lower completion methods in one project: the openhole gravel-pack method for six horizontal wells to develop small and thin sand deposits, the single-zone cased-hole gravel-pack method for a sand-control completion in the three deviated wells, and the dual-zone stack-pack method for two intelligent completion wells for a dual-zone sand-control lower completion.

Time series forecasting based on a novel ensemble‐based network and variational mode decomposition

AbstractStatistical and computational intelligence methods contain weaknesses in handling nonlinearity, non‐stationarity and noise. This research develops a novel decomposition ensemble‐based network named VMD‐DENetwork for time series forecasting over different horizons. A robust decomposition technique called variational mode decomposition (VMD) is applied to decompose the input sequence into several intrinsic modes in a non‐recursive manner. The optimal number of intrinsic modes is selected based on a comprehensive analysis to ensure the stability of the framework. The proposed DENetwork is developed based on stacking architecture and constitutes heterogeneous learners to model the nonlinear and complex relationships. It combines a convolutional neural network, long short‐term memory and an extreme learning machine. A firefly optimization algorithm is adopted for utilizing hyperparameters of the proposed model to enhance the efficiency of VMD‐DENetwork. The forecasting performance is verified by using six real‐world data sets from the New York Mercantile and International Petroleum Exchange. The final obtained results are compared with several peer‐advanced algorithms using the root mean squared error (RMSE), mean absolute error (MAE), Theil inequality coefficient (TIC) and correlation coefficient (R) metrics. The experimental results confirm that the proposed model demonstrates outstanding prediction performance. The employed optimization algorithm is compared with three frequently used bio‐inspired optimization algorithms, and their performance is tested using standard CEC benchmarks.

Multivariate Characterization, Modeling of Paleo Zone Improves History Matching

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 22034, “Rigorous Multivariate Characterization and Modeling of Paleo Zone for Simulation Model History Matching Under Reservoir Uncertainty,” by Nader Y. Bu-Khamseen, SPE, Marko Maucec, SPE, and Anwar R. Awan, SPE, Saudi Aramco, et al. The paper has not been peer reviewed. Copyright 2022 International Petroleum Technology Conference. Reproduced by permission. _ The presence of a paleo zone, which frequently exists below free-water-level (FWL) surfaces, can affect dynamic reconciliation of reservoir simulation models. In the complete paper, the authors present an approach that integrates characterization of paleo zones, parameterization of paleo-zone conductivity, and application of flow profiles as a guide in an accelerated history-matching study of a large-scale dual-porosity/dual-permeability model. The approach to probabilistic parameterization of paleo-zone conductivity has contributed to a model with high quality and rendered a reservoir simulation model with reliable predictive capability in accelerated time. Methods and Models Geological Modeling of Paleo Zone. Structural growth evidences the filling history and displacement occurred by regional tilting, stamping a record of relic (or paleo) oil in the pore system below the current FWL. Applicable saturation-height models are generated based on dedicated core petrophysical rock typing in conjunction with a robust FWL and paleo-oil FWL inversion, a process that allows reproduction of the saturation profile as seen from logs (original logs not affected by production) and the oil-saturation tail as seen below the FWL. The primary methodology behind the approach presented in the paper consists of determining the volume of paleo oil by modeling FWL and paleo-oil FWL surfaces, defining the corresponding paleo zone within the reservoir, and dynamic evaluation of communication between the aquifer, paleo oil, and oil zones; the two surfaces come from an inversion process of the saturation height function. Current developments for the incorporation of the most-important variables affecting dynamic conditions (assisted history matching, uncertainty quantification, multivariate parameterization, and static and dynamic calibration) in the reservoir have allowed incorporation of, and sensitivity studies of, some overlooked parameters, including paleo-oil characterization, modeling, and simulation. Adjusting Petrophysical Properties Inside the Paleo Regions. Petrophysical properties (porosity and permeability) inside the paleo-oil region are modeled based on the bulk volume of water (BVW) from log interpretation. The higher the BVW, the higher the chance of effective communication between the oil leg and the aquifer. These modeled multipliers represent the probability of the sealing character of the paleo-oil region because this accumulated hydrocarbon may not be entirely homogeneous nor uniformly distributed, as suggested by dynamic data and corroborated by core samples. The methodology implemented to represent the presence of the paleo zone in the interpreted and modeled region between the current FWL and the paleo-oil FWL incorporates the use of multipliers in porosity and permeability, allowing the reproduction of the blocking or baffling effect caused by the presence of residual-oil saturation.

Saudi Arabia Case Study Illustrates Road to Zero Routine Gas Flaring

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 21182, “The Road to Zero Routine Gas Flaring: A Case Study From Saudi Arabia,” by Majed Alsuwailem, KAPSARC. The paper has not been peer reviewed. Copyright 2021 International Petroleum Technology Conference. Reproduced by permission. _ The complete paper discusses Saudi Arabia’s progress in gas flaring, the measures the government has taken, and how operators have adapted. It also identifies many lessons learned and technological solutions that could be scaled up on a national or a corporate level to reduce gas flaring to achieve zero routine flaring targets, especially in cases where the state owns hydrocarbon assets and leases them to private operators. History of Gas Flaring in Saudi Arabia Following the discovery in 1948 of Ghawar, Saudi Arabia’s largest oil field, oil production in the country increased and more associated gas was produced and flared. The national oil company, Saudi Aramco, had no interest in capturing gas produced from its oil operations. No local or regional market for it existed, and exporting the gas would have required substantial infrastructure investments. This coincided with periods of low crude oil prices that made gas projects uneconomical. However, as the 1960s and ’70s passed, gas came to be increasingly regarded as an essential part of a broader attempt to diversify the Saudi economy. This, in return, allowed the creation of jobs in new frontiers, including the refining and petrochemical industries. In the early 1970s, the Saudi Ministry of Petroleum and Minerals contracted the Texas Eastern Corporation to conduct a technical and economic feasibility study. It evaluated the benefits of establishing a massive refining and petrochemical industry in the city of Jubail on the Arabian Gulf and Yanbu on the Red Sea, with gas as an important feedstock. The study required major capital expenditures on midstream oil operations. Saudi Aramco, on the other hand, proposed exploiting associated gas to generate electricity. Because the price of oil did not exceed $3/bbl before the 1970s, the Saudi government opted for the first option. Saudi Aramco, however, only foresaw an opportunity in this development if the government contributed major capital to the midstream, resulting in a positive outcome for both the stakeholders and the operator, which turned out to be the case. Master Gas System (MGS) The government gave Saudi Aramco a contract to establish the $12 billion MGS to capture, process, and use gas as fuel and feedstock for the petrochemical plants. Most of this project was paid for by the government. By the fall of 1982, the key components of the MGS (gas-gathering and -processing facilities and pipelines) were fully operational. The MGS saved 4.2 billion scf of gas from being flared, which prevented 80 million tonnes of carbon dioxide from being emitted into the atmosphere annually. Over time, the MGS has been expanded as more oil and nonassociated gas fields have been placed onstream and as demand has risen for dry gas in the power sector. By 2018, the MGS had gathered almost 3.5 trillion ft3/yr and is one of the world’s largest single hydrocarbon networks. It includes 4,000 km of pipelines, 50 gas/oil separation plants (GOSPs), seven gas plants, and two natural gas/liquid units.

Sustainability reporting indicators used by oil and gas companies in GCC countries: IPIECA guidance approach

The purpose of this article is to assess the quality of the sustainability reporting indicators used by oil and gas companies (OGCs) in Gulf Cooperation Council (GCC) countries. This study utilizes the International Petroleum Industry Environmental Conservation Association (IPIECA) guidance as a new robust methodology to assess the quality of sustainability reporting, which is considered a comprehensive benchmark that directly relates to the oil and gas sector. This study conducts a content analysis of the sustainability reports published by OGCs in GCC countries for the 2016–2018 period. The results reveal that the quality of the sustainability indicators disclosed by companies is largely unsuitable. The results also show that companies fail to report detailed information on environmental indicators as the most important category for OGCs. The findings demonstrate that most OGCs in Qatar pay more attention to sustainable reporting indicators than the OGCs in other GCC countries. This study successfully addresses many previously outstanding issues regarding the quality of the sustainability reporting indicators used by OGCs in GCC countries. Hence, the findings paint a clear picture of the situation so that regulators, policymakers, and managers can correct the existing shortcomings in the quality of sustainability reporting and promote sustainability reporting guidance best practices.

Improved Understanding of Minor Reservoirs Optimizes Full-Field Productivity

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 21225, “Defining Heterogeneity and Compartmentalization Predictions of Minor Reservoirs in Fluvial Environments: Geological and Dynamic Context,” by Nur Azah Zulkifli, Lisa C. Chisholm, and Amy M.M. Yusoff, Petronas, et al. The paper has not been peer reviewed. Copyright 2021 International Petroleum Technology Conference. Reproduced by permission. _ Reservoirs in the MN field offshore Malaysia consist of predominantly fluvial delta deposits. Several modeling studies have been performed for major reservoirs. After more than 20 years of production, a project for minor reservoirs has been created. The primary objective of this study was to improve the understanding of the uncertainties affecting well performance and reservoir connectivity and to identify potential infill opportunities. Introduction From the initial analysis of a 2017 full-field review (FFR), the team decided that a detailed subsurface evaluation was necessary. This study was completed with the integration of subsurface data to ensure that hydrocarbon volume and geological knowledge have been calibrated with production performance. The field is 160 km north-northeast offshore peninsular Malaysia in a water depth of 69 m. This field is divided into five areas: Main, West, North, South, and Southwest. The depositional environment of this field is fluvial coastal plain and consists of multistacked oil and gas reservoirs with an average net thickness of 2–20 m, interbedded with shale and coal in a coastal plain setting. Geological Concept and Overview Reservoir X is one of 26 major and minor hydrocarbon-bearing units in the field. Twenty-two minor reservoirs were analyzed for the FFR with an integrated study work flow. Geological analysis concluded that these reservoirs were deposited in a fluvial environment consisting of meandering channels, point bars, overbanks, and abandoned channel-sand mouth bars with deltaic influence (Fig. 1). Seismic data have been used extensively to tackle key uncertainties with either quantitative or qualitative approaches, depending on the seismic detectability limit of the reservoir. The use of seismic in this case was challenging because seismic attributes are not optimal and mostly are used as soft data guided by primary well data. Additionally, several reservoirs required stratigraphic compartmentalization to be introduced. Heterogeneities in the Fluvial Environment Capturing and preserving the different level of heterogeneities was complex because of varied data resolution, grid definitions, and hierarchies of impact. This field has relatively large net-to-gross (NTG) ranges from 20 to 98% with individual channel width averaging from 20 to 100 m. Because the existing dynamic models struggled to replicate field performance, the model created in this study had limited predictive capabilities. The four levels of fluvial heterogeneities of megascopic, mesoscopic, macroscopic, and microscopic scales were used to better understand the heterogeneities of these minor reservoirs. This has helped to compartmentalize the reservoir based on interpretation of the dynamic data without compromising geological understanding.

Well-Integrity Risk-Assessment Strategy Applied to CO2 Sequestration Project

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 22348, “Scrutinizing Well Integrity for Determining Long-Term Fate of a CO2 Sequestration Project: An Improved and Rigorous Risk-Assessment Strategy,” by Parimal A. Patil, SPE, Asyraf M. Hamimi, and M. Azuan B. Abu Bakar, Petronas, et al. The paper has not been peer reviewed. Copyright 2022 International Petroleum Technology Conference. Reproduced by permission. _ Depleted hydrocarbon reservoirs are considered inherently safe for carbon sequestration, but a high density of wells penetrating the carbon dioxide (CO2) storage reservoir could compromise containment performance in a carbon capture and sequestration (CCS) project. A risk-management methodology can be incorporated to evaluate primary and secondary barriers in existing plugged and abandoned (P&A) and development wells to ensure long-term viability of CO2 sequestration projects. The complete paper evaluates well-integrity and CO2 leakage risks along the wells in a depleted field that penetrates the CO2 storage reservoir. Background The identified CO2 storage site offshore Malaysia is a depleted hydrocarbon field discovered in the early 1980s. Subsequently, two appraisal wells were drilled to further assess the field’s development potential. The structure is a north/south anticline with an aerial extent of approximately 35 km2 and a vertical closure of 100 m on top of the reservoirs. Eighteen major and minor gas-bearing reservoirs exist in the field. The hydrocarbons from deeply buried reservoirs were produced over a period of approximately 15 to 25 years through deviated wellbores. In total, 24 wells are in the targeted field; of these, three are abandoned exploration and appraisal wells and 21 are development wells drilled from the platform. All exploration and appraisal wells are P&A, while 21 development wells are still accessible from the platform. High uncertainties are associated with the P&A wells because the well sites were restored per a regulatory requirement in which the casings were cut below mudline and a surface cement plug was placed with no intention of re-entering these wells. Development wells, on the other hand, were assessed and screened for reuse by conversion into CO2 injectors. Understanding Well Integrity for CO2 Storage Potential leakages that may occur through various mechanisms during geological storage of CO2 in the storage field include failed caprock and trap integrity and leakage along existing wellbores. Parameters that could cause leakage of CO2 because of failed caprock include existing faults or fractures, reactivation of faults, development of new fractures during injection, and caprock failure caused by pressures exceeding fracture pressure during or after injection. The geological analysis of the depleted field for potential development as a future CO2 storage site must understand and mitigate associated risks by integrating information from various databases. However, the integrity of wells in the storage project must be ensured over very long time scales, in the thousands of years.

Divided-Time Data-Transmission System Uses a Microchip Storage Ball

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 22368, “Study and Implementation of a Large Amount of Data From a Divided-Time Transmission System Using Microchip-Storage-Ball Release While Drilling,” by Sanguo Li, State Key Laboratory of Shale Oil and Gas Enrichment Mechanism and Effective Development and SINOPEC, and Ruixiang Gao and Jibo Li, SINOPEC, et al. The paper has not been peer reviewed. Copyright 2022 International Petroleum Technology Conference. Reproduced by permission. _ A key question posed in the field is how to transmit logging-while-drilling (LWD) data losslessly back to the surface effectively. Conventional LWD tools face challenges in transmitting all data to the surface efficiently. The complete paper proposes a method that uses the concept of a flash drive downloading and exchanging data among computers. Methodology Two conventional methods exist for data exchange between computers, one of which is network data transmission. The speed of network data transmission determines the efficiency of data exchange between computers. The other method is to use a flash disk to copy and transfer data between computers. Similarly, the downhole LWD tool and the surface data computer can be regarded as two computers. When the bandwidth of the real-time network between surface and underground is limited, the principle of a flash drive dumping and exchanging data between the computers can be used. First, LWD data are dumped into a microchip storage ball (MSB). The circuit sends a release command to the power device to release the MSB from the drill collar. The MSB is carried up to the ground by the drilling fluid and will be recovered on the ground. The data in the MSB then will be uploaded to a computer. The releasable time-divisional data-transmission system mainly consists of MSBs for storing LWD data, sealed chambers for storing the MSBs, a power device for releasing the MSBs, and a circuit for detecting the release signal and controlling the release operation. Large-Capacity MSBs An MSB essentially is a flash drive for storing LWD data. Because of the space constraints of downhole release tools and the limitations posed by the downhole drilling environment, an MSB must have characteristics such as large capacity, small size, high pressure resistance, high temperature resistance, low power consumption, high performance, and high-speed data-dumping capability. In the presented method, the control and power management module controls the data read/write (R/W) command and the power supply to the MSB so that it can read data from the LWD tools and save it using the RS485 communication mode. The network topology of the RS485 mode can send data to multiple MSBs simultaneously. The MSB uses an MSP430 chip to manage reading, writing, and erasing of data. The capacity of the memory chip determines the data capacity of the MSB. Currently, the data capacity of one MSB is 1 Mbit. The diameter of the MSB circuit board is 11 mm. The power supply cable and RS485 cable are connected to the circuit board. This type of wired power supply and data transmission eliminates the need for a battery and a wireless data-exchange module. The MSBs are installed in the sealed chambers of a downhole release tool. Four contacts are designed on an MSB to supply power and to connect the data-circuit system. The four contacts on the MSB are connected to the corresponding four spring contacts in the sealed chambers.

Software-Driven Monitoring Approach Optimizes Well Integrity, Reduces Costs

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 22110, “Digitally Transformative U-WISE Software Technology,” by Nasser M. Al-Hajri, Syed Gilani, and Mohammed Saloojee, SPE, Saudi Aramco, et al. The paper has not been peer reviewed. Copyright 2022 International Petroleum Technology Conference. Reproduced by permission. _ In the complete paper, the authors introduce a model that provides risk-based financial optimization for surveillance programs. The model balances risk with financial investment to provide the asset owner with several optimization scenarios (at low risk and low investment) and ensures that surveys are not overdone. The example used to explain the model is one involving well-integrity surveillance. This example allows the oil operator to obtain a return on past investment made into collecting historical well-integrity data. Well-Integrity Surveys Several different kinds of well-integrity surveys are common in the industry, including the following: - Wellhead-integrity surveys use pressure to investigate the functionality and pressure-sealing integrity of the wellhead tree valves. The primary criterion of a successful wellhead-integrity test is that the valves are able to contain the well pressure without passing pressure outside the well to the surface flowline or the atmosphere. - Surface- and subsurface-safety-valve surveys are another critical test. The primary criterion of a successful surface- or subsurface-safety-valve test is that the valve functions properly by sealing the well pressure when activated. - Landing-base inspection is conducted by electronics that measure the metal loss of the landing base that seats the wellhead tree valves. The primary criterion of a successful landing-base inspection is for the landing base to have an acceptable metal loss without allowing fluid leaks from inside the well. - Annuli surveys are conducted using pressure to investigate the integrity of the cement-filled spaces between each downhole pipe. The primary criteria of a successful annuli survey are that no pressure is measured between the pipes and that no fluid is leaking through the cement from a downhole reservoir to surface. - Corrosion surveys measure the downhole pipes’ remaining metal loss. The primary criterion of a successful corrosion log is to record metal loss for downhole pipes lower than a minimum thickness determined by the well owner as being safe for operations. - Temperature surveys measure the downhole temperature profile and identify possible downhole pipe leaks. Typical downhole temperature profiles are geothermal trends that increase with depth. The temperature surveys not following a typical downhole temperature-gradient profile are flagged as anomalous and are investigated further. The primary criterion of a successful temperature survey is to obtain a downhole temperature recording that conforms to the base temperature-gradient profile without significant increase or decrease of temperature readings. In the complete paper, the authors provide a method of optimization for survey frequency. The temperature survey is used to explain the model work flow.

Studi Pengaruh Kontaminasi Properti Rheology Water Based Mud di Lapangan Sunyu

Studi Pengaruh Kontaminasi Properti Rheology Water Based Mud di Lapangan Sunyu

Integrated Approach Determines Formation-Water Salinity

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 22548, “Integrated Approach for Formation-Water-Salinity Determination,” by Tariq Alshaikhmubarak, SPE, and Laila Mira, SPE, Saudi Aramco, and Sherif Ghadiry, Schlumberger, et al. The paper has not been peer reviewed. Copyright 2022 International Petroleum Technology Conference. Reproduced by permission. _ In the complete paper, two methodologies are tested to achieve measurement of formation-water salinity. First, a novel dry-weight chlorine (DWCL) measurement from an advanced spectroscopy tool is used to estimate the formation salinity at the depth of investigation of the device. The second methodology uses a new downhole induction resistivity cell in the formation-tester tool. The chlorine measurement, along with the flowline-induction-resistivity measurement, helps enhance the quality of saturation evaluation for quick decision making during logging operations and acceleration of evaluation studies instead of waiting on laboratory results. Chlorine Work Flow The ability to quantify chlorine concentration can help derive formation salinity as a continuous curve. Because chlorine has a large capture cross section, it is possible to extract it from capture gamma ray spectra with acceptable uncertainty, but the real challenge is to split the total chlorine signal seen by the tool into formation chlorine signal and borehole contribution. The chlorine signal split is a fundamental step in this work flow, outlined in Fig. 1. Once the chlorine concentration in the formation is obtained—expressed as DWCL—several petrophysical applications are enabled. The first is computation of water volume assuming a known formation-water salinity. The second is computation of the sodium chloride (NaCl) equivalent salinity from an independent volume of water and DWCL. Finally, one can solve for the NaCl equivalent water salinity. Equations to achieve these steps are provided in the complete paper. Interpretation Considerations Capture spectroscopy measurements have a shallow depth of investigation (DOI) in the range of 8–10 in., which means sensitivity to mud-filtrate invasion in the volume of rock probed by the tool. The mud-filtrate invasion is controlled by several factors, including mud overbalance, formation exposure time to mud, formation porosity and permeability, and mudcake-formation process and efficiency. These factors must be considered when using the chlorine work flow to assess the effect of the invading water-based-mud (WBM) filtrate, which normally has a different salinity than the formation water. The main effect of oil-based-mud (OBM) filtrate invasion, assuming that only the oil phase is invading the formation, is a reduction of water volume at the measurement DOI, degrading the statistical precision of the DWCL and increasing the uncertainty in the computed salinity.

Machine Learning Assists Bit Selection and Optimization

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 21299, “Drilling in the Digital Age: Machine-Learning-Assisted Bit Selection and Optimization,” by Peter Batruny, SPE, Hafiz Zubir, and Pete Slagel, SPE, Petronas, et al. The paper has not been peer reviewed. Copyright 2021 International Petroleum Technology Conference. Reproduced by permission. _ The project outlined in the complete paper describes machine learning as a powerful tool for bit selection and parameter optimization to improve drilling performance. Machine learning will become a significant part of well planning, design, and operations in the future. The study demonstrates how artificial neural networks (ANNs) can be used to learn from previous operations and influence planning decisions to improve bit performance. Introduction Multiple wells have been drilled in an onshore field in Iraq using different bit designs and with a variety of downhole conditions. To improve the rate of penetration (ROP) in a significant manner, a radical shift in how drill bits are selected, as well as a closer look at bit characteristics, is needed. This work aims to combine analytical and physical models to examine aspects of bit designs previously overlooked. Two mathematical models traditionally have been used for bit selection, the cost per foot (CPF) model and the mechanical specific energy (MSE) model. This work concludes that MSE is more effective than CPF in optimizing ROP and is a valid benchmark for comparing bits. MSE can be used to compare previous bit runs but is limited in predicting ROP for future bit runs. Equipment and Processes Data governance consists of data collection, processing, cleaning, and compilation. Data are collected from American Standard Code for Information Interchange logs in real time and then are processed by removing missing values. The data sets are split by individual bits, with each bit characterized by data compiled from multiple wells in which the bit was run. Throughout this paper, ROP will refer to instantaneous on-bottom ROP. Given the success that ANNs have had, and continue to have, in predicting ROP in the literature, they are used for this work. Once a model is established based on statistical and physical performance, it is used as a base model to run optimization analysis for each bit. This paper examines two methods of optimization, the first being sensitivity analysis based on average ROP. The second optimization method used in this study is a Monte Carlo-style optimization. Once optimal parameters are generated from the sensitivity analysis and Monte Carlo models, they are plotted against the modeled values of offset ROP. This acts as a further verification of the optimal parameters to ensure they are within range of actual historical parameters. The optimal values are then implemented in future wells.

Dual-Frequency Desalting Technology Breaks Bottlenecks, Lowers Cost of Ownership

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 22365,“No More Inefficient Crude Desalting: Breaking Bottlenecks With Dual-Frequency Technology Lowering Total Cost of Ownership,” by Prabhu Elumalai, Gary Sams, and Umanath Subramani, Schlumberger, et al. The paper has not been peer reviewed. Copyright 2022 International Petroleum Technology Conference. Reproduced by permission. _ A major independent crude oil refinery in Asia is processing crude oil in two crude distillation units (CDUs) using an alternating-current (AC) desalting system. Because of inefficient desalting, only 60% desalting efficiency was achieved for each train with subsequent low dehydration efficiency. After a holistic review of the entire desalting operation, the service company recommended upgrading the CDU 1 desalter vessel to dual-frequency technology and adding a new dual-frequency desalter at the second stage of the CDU 2 vessel. The complete paper examines the successful project from early engagement through project execution leading. Refinery Desalters _ Overview of Case-Study Refinery. The refinery was operated with a design capacity of 206,000 B/D through CDUs 1 and 2. CDU 1 included two trains of two-stage legacy AC desalters (Trains 1 and 2). Train 1 operated with 40% of CDU 1’s total flow (60,000 BOPD), while Train 2 operated with 60% of CDU 1’s total flow (90,000 BOPD). The AC desalting system desalted and dehydrated crude oil before feeding the crude to preheated trains. The desalters in this refinery operated for 20 years with the AC technology. Dual-Frequency AC/Direct Current (DC) Desalter Configuration. AC crude dehydration technology is over a century old. The complete paper recaps different types of AC desalter configurations, but this synopsis concentrates on dual-frequency AC/DC desalter configurations. The vessel design for the dual-frequency technology is identical to that of the AC/DC vessel, with similar spreaders, electrodes, and collectors. What differentiates the dual-frequency technology is the power unit, which functions with two frequencies for dehydration and desalting. The base frequency typically is in the range of 800–1,600 Hz, and the modulation frequency is in the range of 0.5–4 Hz. The computer-based controller controls the output of the variable voltage/frequency power unit and produces a nearly infinite number of waveform configurations. Also, these units facilitate online changing of maximum voltage, minimum voltage, base frequency, and modulation frequency applied to the electrode. Conventional power units cannot be operated beyond 40% of their rating. The dual-frequency power unit, however, can operate successfully beyond 80% of its rating. The combination of AC/DC fields with dual-frequency performance provides the high water tolerance of the AC field, the high efficiency of the DC field, and the improved desalting offered by the dual-frequency voltage pattern. This combined electrostatic technology offers more-efficient bulk water and small-water-droplet removal from the crude oil. Highly efficient dehydration means smaller treaters, better performance, lower operating temperatures, and fewer demulsifier chemicals. Further improvements include optimized electrode configurations and enhanced fluid distribution inside the electrostatic treaters.

Nigeria’s Vulnerability to Global Oil Dynamics and Politics

The paper analysed global oil dynamics and politics and their implications for Nigeria’s development. It adopted systems theory as its theoretical framework and employed the qualitative method as its methodology, in which face-to-face interview was used in obtaining primary data from relevant respondents alongside secondary data from relevant academic works. The paper found out that Nigeria has been negatively affected by the changing dynamics of international petroleum politics, particularly by the fall in global oil prices, as Nigeria depends heavily on oil earnings to meet its budgetary provisions for national development. This is further compounded by mismanagement of the accrued oil wealth before the collapse of oil prices and increased geopolitical tension. Nigeria should without further delay, diversify its economy away from oil to other viable and less volatile sectors, such as agriculture and solid minerals, manufacturing, Information and Communications Technology (ICT), aviation services and so on, alongside the strengthening of its bargaining power in global petroleum politics, particularly in the Organization of Petroleum Exporting Countries (OPEC), availing itself of the advantage of its leadership position in OPEC and the political leverage it has as a strategic actor in international oil politics.

Study Investigates Foam Use for Control of Pipeline Slugging

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 22235, “Foams To Control Slugging Issues in Pipelines—From Laboratory to Simulation,” by Ivy C.C. Hsia, Bishop Falope, and Nor Hadhirah Halim, Petronas, et al. The paper has not been peer reviewed. Copyright 2022 International Petroleum Technology Conference. Reproduced by permission. _ In one of the operator’s Malaysian fields, hydrodynamic slugging, or two-phase liquid/gas flow instability in the pipeline, has caused losses in flow capacity and intense vibration at the separator, leading to integrity issues. To understand how the behavior of foams in a pipeline affect or alleviate slugging performances, foam behavior was simulated using the OLGA (short for “oil and gas”) simulator, a commercial dynamic multiphase-flow-simulation software. This study showed that foams were able to slow gas velocity and diminish liquid fluctuations, thus reducing slugging in a problematic pipeline. Challenges Posed by Slugging Hydrodynamic slugging or instability of waves at certain liquid/gas flow rates in the pipeline were concerns in several fields in Malaysia. In one such field, almost 50% of the loss in flow capacity (i.e., liquid holdup) from a producing pipeline was the result of slugging, causing gas-production deferments of as much as 30 million scf/D. Severe vibrations from the pipeline to the separator often were felt at the platform, leading to questions about the mechanical integrity of the separator and anticipated high maintenance costs. The issues of slugging can be solved with the use of foams introduced into the pipeline to slow down gas velocity and enhance mixture with liquid. Foam injection into the wellbore has proved to act as a flow stabilizer, thus removing the slugging in the well and improving gas lift. Foams from surfactant injection increase the viscosity of gas, thus reducing gas movement and velocity but with a pressure penalty. Surfactant concentration also decreases the liquid’s surface tension to a minimum value reached when micelles start to form, called the critical micelle concentration (CMC). A thorough understanding of reduction of liquid surface tension is critical. The inclusion of crude oil into the authors’ laboratory tests is intended to establish the actual performance of the surfactant and the effect of crude oil on viscosity and interfacial tension (IFT) to replicate actual fluid properties (i.e., water cut and emulsion tendencies of the field). The software used simulates flow under actual pipeline conditions. A base model was built to establish slugging conditions using parameters obtained from the field. The model was modified to include input parameters of foams such as viscosity and IFT between two phases to determine if they can suppress foams; this was achieved by reading changes in the total liquid volume flow coming from the pipeline throughout the extent of the pipeline. In the complete paper, the authors sought to understand how to determine foam viscosity and interfacial tension in the presence of crude oil using precision laboratory instrumentation and then used these measurements as inputs into the simulation software to calculate the percent reduction in liquid flow volume and fluctuations of an actual pipeline facing slugging issues.

Study Investigates Mechanisms for Damage vs. Uplift in Different Basins

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 22194, “Modeling Frac Hits: Mechanisms For Damage vs. Uplift,” by Garrett Fowler, SPE, Dave Ratcliff, SPE, and Mark McClure, SPE, ResFrac. The paper has not been peer reviewed. Copyright 2022 International Petroleum Technology Conference. Reproduced by permission. _ Parent/child interactions pose a critical challenge for oil and gas shale producers. The industry has progressed significantly in its understanding of causes and mitigation. However, important uncertainties remain. Fracture-driven interactions, or “frac hits,” exhibit varied behaviors in different basins. The authors of the complete paper examine and contrast a case study in the Bakken in which production uplift occurs with observations of production loss in a case study in Oklahoma. Introduction Publicly available data on frac hits across the Bakken, Eagle Ford, Haynesville, Woodford, and Niobrara show that, in the Bakken and Haynesville, greater than half the documented frac hits resulted in production uplift in the hit well (parent well). Conversely, in the Woodford and Niobrara, more than half of the frac hits resulted in a negative effect on the parent well. In the Eagle Ford, multiple interactions result in a negative effect on the parent well. Several studies in the Woodford examined the formation of “gummy bears” in the parent well post-frac hit. This is a colloquial term for a semisolid mixture containing hydrocarbons, sand, iron, fine particles from clay, and, sometimes, amounts of friction reducer. These gummy bears clog or reduce the conductivity of the fracture network downhole in the wells that are hit, reducing the productivity of the well. While other basins have provided evidence of the phenomenon, evidence of gummy bears is absent from many shale basins, particularly those showing production uplift after frac hits. Methodology The authors investigate potential mechanisms for production uplift and damage in a fully coupled hydraulic fracture and reservoir simulator. The model captures poroelastic stress response from depletion, multiwell fracture interaction, asymmetric fracture growth, multiphase flow in hydraulic fractures as they are reopened during a frac hit, and proppant remobilization. Numerical models force a self-consistent representation of physics. Every model output is a necessary consequence of a model input.