Upstream Oil Research Articles

The synergistic effects of cationic surfactant and smart seawater on the recovery of medium-viscosity crude oil from low-permeability carbonates

In the petroleum industry, there is a continuous search for cost-effective enhanced oil recovery (EOR) methods to increase oil extraction. Surfactant-based EOR is one of these effective methods, which is applied after the primary and secondary recovery phases. This paper presents an experimental study on the use of a cationic surfactant, hexadecyltrimethylammonium bromide (CTAB, CH3(CH2)15N(Br)(CH3)3), and smart seawater (SW) for EOR in low-permeability carbonate rock with medium viscosity crude oil. Smart SW was prepared by modifying the concentrations of Ca2+, Mg2+, and SO42- in synthetic offshore SW. The aqueous stability of CTAB was tested in different salinities of smart SW at the reservoir temperature. It was demonstrated that CTAB is stable at 55 °C, which was further confirmed through optical transmittance measurements, revealing values mostly exceeding 93%. The use of smart SW and CTAB significantly altered the wettability of carbonate rock towards water-wet and reduced the interfacial tension (IFT) between crude oil and water, reaching levels below 0.087 mN/m. However, the presence of smart SW increased the adsorption of CTAB onto the surface of carbonate rock. Nevertheless, the adsorption values were significantly below 1 mg/g-rock. Smart SW + CTAB resulted in a total oil recovery of 76.71% of original oil-in-place (OOIP), compared to 71.70% of OOIP with unmodified SW + CTAB. These results suggest that the use of smart SW in combination with CTAB is a promising approach for enhancing the recovery of medium-viscosity oil from tight carbonate reservoirs. Findings from this study can help in better understanding the optimal conditions for the application of smart SW-CTAB flooding to improve the effectiveness of tertiary recovery operations in the upstream oil sector.

Microsoft Excel Program Training at the Dumai Petroleum Vocational School, Riau Province

Education at the Vocational High School (SMK) level is an important alternative for students to develop their skills and be ready to face competition in an increasingly competitive job market. SMK graduates have technical skills and are ready to enter work sectors related to procedures and routines. In Riau Province, the upstream oil and gas industry provides opportunities for SMK graduates to participate in this sector. SMK Migas in Duri City and Dumai City were established to prepare students for positive contributions to the oil and gas industry around the region. The development of technology, especially in the field of information technology, encourages the industry to apply the technology in every aspect of its operations. Modernization and digitalization also affect the oil and gas industry sector, which includes exploration and exploitation activities. The oil and gas industry requires reliable human resources (HR), given the density of capital and technology in this sector. However, companies tend to look for experienced workers, so SMK graduates need to have skills that can be directly used in the oil and gas industry. The transition to an increasingly advanced technological era requires SMK graduates to have the ability to adapt to technology, especially in the use of computers as a means of work and learning. Behave=adaptive Being able to operate the Microsoft Office program package is an important requirement for every individual who uses a computer, either in the form of a personal computer (PC) or laptop. Laptops are also the main device for freelance engineers in conducting engineering analysis from simple to complex.

Estimation of natural methane emissions from the largest oil sand deposits on earth.

Worldwide methane emission by various industrial sources is one of the important human concerns due to its serious climate and air-quality implications. This study investigates less-considered diffusive natural methane emissions from the world's largest oil sand deposits. An analytical model, considering the first-order methane degradation, in combination with Monte Carlo simulations, is used to quantitatively characterize diffusive methane emissions from Alberta's oil sands formations. The results show that the average diffusive methane emissions from Alberta's oil sands formations is 1.56 × 10-4 kg/m2/year at the 90th percentile of cumulative probability. The results also indicate an annual diffusive methane emissions rate of 0.857 ± 0.013 Million tons of CO2e/year (MtCO2e/year) from Alberta's oil sands formations. This finding suggests that natural diffusive leakages from the oil sands contribute an additional 1.659 ± 0.025 and 5.194 ± 0.079% to recent Canada's 2019 and Alberta's 2020 methane emission estimates from the upstream oil and gas sector, respectively. The developed model combined with Monte Carlo simulations can be used as a tool for assessing methane emissions and current inventories.

CRISES AS HARBINGERS OF OPPORTUNITIES: AN EMPIRICAL INSIGHT OF KNOWLEDGE MANAGEMENT AS MODERATOR BETWEEN ABSORPTIVE CAPACITY AND STRATEGIC AGILITY

The upstream oil and gas businesses in Nigeria suffer from insufficient absorptive capacity, poor knowledge management intheir operations, and a lack of capability to address difficulties in the country effectively. These factors impeded their capacity to bestrategically agile in reacting to the sector’s issues, eventually stifling their performance. This study investigated the moderating influence of knowledge management on the relationship between absorptive capacity and strategic agility in the upstream oil and gas industry of Nigeria. A survey research design was used. Instruments were sent to the upper and intermediate management of upstream oil and gas businesses in Lagos State. The validity and reliability of the instrument were examined, and the findings indicated that the questionnaire was valid and reliable. Smart Partial Least Square (PLS) 3.0 was used for data analysis, coupled with Structural Equation Modelling. The research indicated that absorptive capacity had a substantial impact on strategic agility and that knowledge management strengthened the association between absorptive capacity and strategic agility among the chosen upstream oil and gas enterprises in Lagos State, Nigeria. The study recommended that upstream oil and gas businesses employ good knowledge management methods and construct excellent absorptive capabilities to financially engage strategic agility measuresthat will guarantee greater success than their sector competitors. The study’s theoretical and managerial ramifications, as well as its limits and future research opportunities, were discussed.

Adaptive Scenario Planning Development for Indonesian Upstream Oil and Gas Industry: Case Study of PT Kelola Migas in Managing Mature Field Phase

The global economic conditions after the COVID pandemic, which have not fully recovered, the vulnerability of global oil prices due to unpredictable external factors, global pressure for decarbonization efforts and the fulfillment of Environmental, Social and Governance (ESG) parameters to support energy transition, the less competitive condition of oil and gas reserves in Indonesia, and the contract schemes and fiscal incentives in Indonesia that are considered unattractive by investors are part of the tip of the iceberg of uncertainty in the external conditions of the upstream oil and gas industry in Indonesia. In relation to the above conditions, PT Kelola Migas (PT KM) requires a comprehensive strategy formulation process based on a long-term understanding of potential future scenarios that focus on external factors as uncontrollable factors that will significantly impact the company. This research is conducted with a focus on the use of adaptive scenario planning methodology, which will provide a fresh perspective for PT KM in utilizing strategic tools oriented towards the medium and long term. Exploring the implications and mitigation options for each scenario is conducted to provide strategic choices in facing potential situations. The identification of early warning signals for each scenario is also carried out as indicators of changes in the current situation towards one scenario or another.

ANALISIS KEEKONOMIAN SKEMA PSC GROSS SPLIT PADA PENGEMBANGAN LAPANGAN FR

Based on the Regulation of the Minister of Energy and Mineral Resources Number 52 of 2017, which later this regulation was revised into Regulation of the Minister of Energy and Mineral Resources Number 12 of 2020 the government has issued a new regulation related to the upstream oil and gas business, namely the Gross Split Production Sharing Contract scheme. In this scheme, the contractor will bear all operational costs during the development of the oil and gas field, and there is a distribution of amounts for the government and publications that are imposed before tax, the components are a base split, variable split, and progressive split. An analysis of the widespread use of the assessment components is necessary. This research will calculate the economics of the Fr field with production calculations starting in 2023. The Fr field is a field that produces oil and gas with a total oil production of 14765 Mbbl and gas of around 1,972,045 Mscf until 2036. The analysis is carried out to determine economic indicators by the calculation results for the acquisition of the Gross Split Production Sharing Contract scheme provide positive benefits for contractors in the Fr field, with a total NPV@10% of 424,010 MUSD with an IRR of 24% and a Pay Out Time of 6 years. By conducting a sensitivity analysis, the parameters that most influence the NPV and IRR in the Fr field are oil and gas production & prices.

Data-driven approach to dynamic uncertainty quantification of oil well production: Decline curve analysis and Hidden Markov Model

The upstream oil and gas industry has already used decline curve analysis to forecast oil flow rates and estimate the ultimate recovery for decades. Despite its popularity, the applications are theoretically limited and could not handle irregular variations in oil well flow behavior. In other words, it is a method for predicting the general behavior of oil wells rather than providing reliable information in specifics. It is mostly irritated by subjective implementation and a single offer of a solution without uncertainty quantification.The Hidden Markov Model (HMM) was employed in this work for dynamic uncertainty quantification in oil well flow forecast and estimated ultimate recovery (EUR). It is performed by determining the set of appropriate decline curves along with the corresponding probabilities. HMM has three main parameters: the probability transition matrix (A), the emission probability matrix (B), and the prior distribution. All these parameters can be learned from data using the Baum-Welch algorithm. The trained HMM was utilized to generate the posterior. Accordingly, using HMM and learning from the data, a dynamic probabilistic decline curve analysis is conducted. It preserves the decline curve's strength of simplicity while also covering the flaws of subjectivity and lack of uncertainty quantification. The novelty of our study is that it focuses on dynamic uncertainty quantification of oil production forecasts using new observations and covers any regular or irregular (planed or naturally stochastic) variations of flow trends. We implemented the method in cases with the variation of the flow rate by choke opening and also a sharp decline in the late time, which are not covered by decline curve analysis and not proposed in previous studies. Dynamic predictions by HMM followed the variations in flow patterns obtained by the new observations. In addition, the calculated data-driven probability distribution of EUR acceptably covers the true values.

Saskatchewan’s oil and gas methane: how have underestimated emissions in Canada impacted progress toward 2025 climate goals?

Canada has set ambitious methane emission reduction targets for its oil and gas industry, and recently, the province of Saskatchewan—Canada’s second largest oil producing region—announced it has already exceeded the first of these targets. Using detailed operator-reported emissions data, published for the first time from Saskatchewan in 2022, we estimate the province’s upstream oil and gas methane inventory to independently evaluate the reported emission reductions. While the inventory suggests that Saskatchewan has surpassed its target, the inclusion of recently published site-level aerial measurement data from cold heavy oil production with sand (CHOPS) wells suggests that the methane inventory is underestimated by between 30% and 40%. This inventory update is supported by new regional aerial measurements confirming the continued underestimation of emissions at CHOPS wells. Since these emissions likely evade required reduction under current regulations, we evaluate achievable emission levels if such CHOPS emissions are accurately measured/reported. The results show Saskatchewan can achieve much deeper emission reductions under current regulations with improved emission measurement, reporting, and verification methods. We discuss the benefits and risks inherent in Saskatchewan’s regulatory approach where emission limits are primarily set at the operator-level.

Grand Challenges for the Oil and Gas Industry for the Next Decade and Beyond

_ The oil and gas industry faces a rapidly changing world of multiple challenges and opportunities, especially with growing climate and sustainability concerns. About a decade ago, SPE conducted a series of workshops to define the grand challenges in technology and R&D for the upstream oil and gas industry for the following decade. It identified 5 + 1 grand challenges (Table 1). To define the set of grand challenges for the next decade, in a much more unpredictable environment, we held an SPE workshop in Austin, Texas, in January 2023. Panelists from IOCs, NOCs, and service companies, as well as environmental and financial stakeholders in the emerging energy system, surveyed the rapidly changing energy landscape. The workshop then facilitated sessions of the more than 120 thought leader participants to define grand challenges that are impactful for society and our industry and have a significant R&D/technology component that is aligned with the capabilities of the SPE membership. We arrived at a list of five technical grand challenges: improved recovery from tight/shale resources, net-zero operations, carbon capture, utilization, and storage (CCUS), geothermal energy, and digital transformation. Additionally, we identified a sixth “bonus” nontechnical challenge—education and advocacy, since we believe that more effective engagement with thought leaders outside our industry will be required to advance and deploy new technologies in all five of these areas. Table 2 summarizes the technical challenges and their impacts. We believe that this work will help the industry focus its R&D and technology efforts on the highest-value activities for both industry and society. We now summarize each of these new grand challenges. Improved Recovery From Tight/Shale Resources Notwithstanding the rapid growth of non-hydrocarbon energy sources and carriers, oil and natural gas demand are projected to continue rising through 2050 (EIA 2023). In the past 20 years, horizontal drilling and hydraulic fracturing were combined to extract hydrocarbons from unconventional shale resources, which helped us meet rising global oil demand. However, production from existing shale oil wells declines quickly, and ultimate recoveries are often less than 10%. To meet global demand, we must improve recovery with minimal environmental impact. Tight and shale oil reservoirs have unique challenges. For example, shale reservoirs are subject to clay swelling and formation damage. Permeabilities are ultra-low, often on the order of nano-Darcys, which leads to extremely low flow rates and to transport dominated by diffusion. Thus, hydraulic and natural fractures are necessary, and geomechanics/rock compaction plays an important role. Many traditional improved oil recovery (IOR) strategies are challenging in tight and shale reservoirs. The small pores make waterflooding techniques difficult, and the low permeability hampers well-to-well methods. Thus, single-well, huff-and-puff strategies are the most common IOR methods. Injectants include miscible and immiscible gases (CO2, CH4, and N2) and chemicals (surfactants, solvents, and nanoparticles). In addition, thermal methods may allow control of oil viscosity and pressurization of the reservoir.

Gas flaring-induced impacts on aquatic resources in the Niger Delta Region, Nigeria

The Niger Delta is the Nigerian oil and gas province. About 10 – 40% of produced associated gas is underutilized and is flared into the environment. Gas flaring is the burning of natural gas and petroleum hydrocarbons in flare stacks by upstream oil companies in oil fields during operations. Flaring operations have adverse impacts on the environmental components and its aquatic resources. This paper reviewed the impacts of gas flaring on aquatic resources in the Niger Delta Region of Nigeria. The study revealed the induced thermal impacts on the aquatic environment to include alteration of ionic components, pH, temperature, conductivity, heavy metal concentration especially in rain water which could cause death of aquatic biota. Water toxicity from acid rain and heating from flare stacks had also caused some fish species to become extinct. Exposure to harmful air pollutants generated during incomplete combustion of gas had been linked to a variety of health hazards such as: cancer, neurological, reproductive and developmental consequences. It also affects vegetation leading to decrease in growth and productivity probably due to changes in soil quality parameters in the aquatic environment. Climate change has an impact on both physical and biological habitats, influencing biodiversity both directly and indirectly via interactions with other environmental factors. It is recommended that strict government legislations on how gas production projects may be conducted should be introduced and monitored. Regulatory agencies must fulfil their responsibilities of enforcing laws and regulregulations to check gas flaring activities in order to protect the aquatic resources of the Niger Delta Region.

Waste cooking oil invert emulsion drilling mud formulation with an effective H2S scavenging performance

Encountering hydrogen sulfide while drilling/stimulating subterranean formations is very common in upstream oil and gas industry. If not effectively scavenged in-situ, this lethal gas will escape to the surface causing serious health and safety problems and potential losses in human lives, in addition to significant economic penalties. Additionally, the release of waste cooking oils to the drainage/sewage systems will lead to some serious operational problems during the treatment of the collected sewage wastewaters. Thus, the key objective of this study is to convert the waste cooking oils from a burden into a valuable commodity via utilizing them for the formulation of invert emulsion drilling fluids. The waste cooking oil invert emulsion drilling mud was stabilized partially by rhamnolipid biosurfactant as a secondary emulsifier. The mud also contained hydrophobic zinc nanoparticles (NPs) as a weighting agent. To provide these waste cooking oil-based drilling muds with an effective H2S scavenging performance, a small quantity (1 wt%) of potassium permanganate was added. Despite the small quantity of the added scavenger, the mud formulation was able to scavenge 99.4 and 237.7 mg H2S/g scavenger at the breakthrough and saturation time, respectively. These H2S scavenged capacities demonstrate the feasibility of incorporating potassium permanganate, which is cheap and abundant material, into waste cooking oil invert emulsion drilling mud formulations. The flow behavior and the viscosity of the waste cooking oil-based mud comprising the H2S scavenger were found to be comparable to those reported in the literature for oil-based muds (OBMs) containing NPs.

Promoting financial stability of oil producers: Operational vs. financial hedging

This paper investigates the effects of operational hedging on commodity price risks. It explores a novel type of operational hedging, i.e., the natural operational hedge position between upstream crude oil production and downstream activities in the supply chain. Using hand-collected data from 293 unique oil-producing firms, we find that operational hedging is sufficiently effective in reducing firms’ exposure to oil-price risk. We also find an inverse relationship between operational and financial hedging, suggesting that they can substitute for each other.

Executing Upstream Oil and Natural Gas Business Activities: Legal Status and Authority of the Oil and Gas Special Working Unit (SKK)

The Oil and Gas Special Task Force (SKK Oil) is a government agency responsible for controlling and supervising upstream oil and gas businesses. This study aims to examine the legal position of SKK Oil as the executor of national upstream oil and gas business activities and its role in promoting national energy security. The research utilizes an empirical juridical legal research method with qualitative research specifications, providing a focused and in-depth analysis of the subject matter. Secondary data obtained from primary, secondary, and tertiary legal sources are used in this study. The findings reveal that the National Oil and Gas Management Policy has not fully aligned with the goal of achieving national energy security.

The Authority of Oil and Gas Special Task Force as a Company Holder and Implementers of Upstream Oil and Gas Bussiness Activity: a Juridical ViewPoint

In 2001, Law No. 22 of 2001 concerning Oil and Gas was enacted, which aimed to regulate Pertamina's authority in the oil and gas sector, as well as grant rights and authority to other domestic and foreign oil companies. Consequently, this limited Pertamina's ability to explore and exploit new oil fields. This article adopts a normative juridical research method, which seeks to address existing legal issues through this approach. The research method includes the Case Approach, Statute Approach, and Conceptual Approach, which will be utilized by the author. Through this approach, the compatibility between legal provisions and their implementation will be examined. The findings indicate that, according to statutory regulations, the government agency responsible for upstream oil and gas activities in Indonesia was initially the Executive Agency for Upstream Oil and Gas Business Activities (BP Migas), which was later replaced by the Special Task Force (SKK) for Oil and Gas. The Constitutional Court dissolved BP Migas based on the decision that BP Migas solely controlled and supervised oil and gas management, without engaging in direct management activities. This led to a relationship model between BP Migas, as a representative of the state, and business entities, which contradicted the constitutional principle of state control over oil and gas natural resources.

Securing State’s Asset: Legal Protection of Natural Resources of Oil and Gas

The legal framework for oil and natural gas activities in Indonesia is established by Law Number 22 of 2001 concerning Oil and Natural Gas, which was officially published in the State Gazette in 2001. SKK Migas, which replaced BP Migas, is responsible for the management of upstream oil and gas activities based on Cooperation Contracts (KKS). The upstream activities are conducted through Cooperation Contracts (KKS) as specified in Article 6 of the Oil and Gas Law. According to Article 1, number 19 of the Oil and Gas Law, a Production Sharing Contract (PSC) refers to a cooperative arrangement that aims to maximize the benefits from exploration and exploitation activities for the state and ensure the welfare of the people.

Direct measurement of methane emissions from the upstream oil and gas sector: Review of measurement results and technology advances (2018–2022)

The increasing methane emissions from the upstream oil and gas sector deviates from the goals of the Paris Agreement on sustainable development and climate control. This paper reviews recent direct measurement results and technological advances in the upstream oil and gas sector, based on more than 100 sources published between 2018 and 2022. No consensus was found on the correlation between methane emissions and well data items such as production volume and well age. Aircraft surveys were the most frequently used technology during the study period. Developed countries lead in direct measurement, with only 12.5% of studies conducted in developing countries. The sensing method and the performance of sensor carriers lead to different characterisations of direct measurement techniques. Growing upstream methane emissions accelerate global warming and pose risks to groundwater. Mitigating super-emitters and reported venting and flares could reduce total methane emissions by 20% and 25%, respectively. China, the world's largest methane emitter, emitted approximately 2135 kt methane from its upstream oil and gas sector, mainly through venting (80%). Direct methane measurements and the strength of government management could assist China in prioritising carbon emission reduction and filling the legislative gap.

Satellite quantification of methane emissions and oil–gas methane intensities from individual countries in the Middle East and North Africa: implications for climate action

Abstract. We use 2019 TROPOMI satellite observations of atmospheric methane in an analytical inversion to quantify methane emissions from the Middle East and North Africa at up to ∼25 km × 25 km resolution, using spatially allocated national United Nations Framework Convention on Climate Change (UNFCCC) reports as prior estimates for the fuel sector. Our resulting best estimate of anthropogenic emissions for the region is 35 % higher than the prior bottom-up inventories (+103 % for gas, +53 % for waste, +49 % for livestock, −14 % for oil) with large variability across countries. Oil and gas account for 38 % of total anthropogenic emissions in the region. TROPOMI observations can effectively optimize and separate national emissions by sector for most of the 23 countries in the region, with 6 countries accounting for most of total anthropogenic emissions including Iran (5.3 (5.0–5.5) Tg a−1; best estimate and uncertainty range), Turkmenistan (4.4 (2.8–5.1) Tg a−1), Saudi Arabia (4.3 (2.4–6.0) Tg a−1), Algeria (3.5 (2.4–4.4) Tg a−1), Egypt (3.4 (2.5–4.0) Tg a−1), and Turkey (3.0 (2.0–4.1) Tg a−1). Most oil–gas emissions are from the production (upstream) subsector, but Iran, Turkmenistan, and Saudi Arabia have large gas emissions from transmission and distribution subsectors. We identify a high number of annual oil–gas emission hotspots in Turkmenistan, Algeria, and Oman and offshore in the Persian Gulf. We show that oil–gas methane emissions for individual countries are not related to production, invalidating a basic premise in the construction of activity-based bottom-up inventories. Instead, local infrastructure and management practices appear to be key drivers of oil–gas emissions, emphasizing the need for including top-down information from atmospheric observations in the construction of oil–gas emission inventories. We examined the methane intensity, defined as the upstream oil–gas emission per unit of methane gas produced, as a measure of the potential for decreasing emissions from the oil–gas sector and using as reference the 0.2 % target set by the industry. We find that the methane intensity in most countries is considerably higher than this target, reflecting leaky infrastructure combined with deliberate venting or incomplete flaring of gas. However, we also find that Kuwait, Saudi Arabia, and Qatar meet the industry target and thus show that the target is achievable through the capture of associated gas, modern infrastructure, and the concentration of operations. Decreasing methane intensities across the Middle East and North Africa to 0.2 % would achieve a 90 % decrease in oil–gas upstream emissions and a 26 % decrease in total anthropogenic methane emissions in the region, making a significant contribution toward the Global Methane Pledge.

IMPLEMENTATION OF MAINTENANCE AND RELIABILITY MANAGEMENT SYSTEM (MRMS) IN PERTAMINA HULU ENERGY SUBHOLDING UPSTREAM (PHE SHU) THROUGH FIELD ASSESSMENT OF ISO 55001

As part of the integrated efforts that need to be made to achieve the target of becoming a world-class energy company, PHE SHU seeks to carry out the implementation of the Asset Integrity Management System (AIMS) and develop a MRMS which involves a solid team and is able to complete implementation in a timely, effective, efficient and highly competitive manner, to achieve a production target of 1 million bbl/day and 12 bcf/day in 2030 for national energy security referring to the international standard ISO 55001. MRMS is a reference for the governance of the reliability program and maintenance of production facility assets in the Upstream Subholding environment in the operational phase of the Pertamina Group asset management life cycle. identification of Failure Mode Effect Analysis (FMEA) preparation of maintenance strategy programs in the form of task selection for failure mode control based on studies in FMEA namely preparation of detection work programs in rotating equipment in the form of Predictive Maintenance (PdM) activities, task selection of detection programs in static equipment in the form of RBl activity. Task selection prevention in the form of Preventive Maintenance (PM) activities. Failure finding (function test), including determining time intervals for carrying out inspection activities for the PdM, RBI, PM, function test, ORDC (Operator Routine Duty Check List) programs based on the historical failure rate stated in PAREDA in ensuring that Upstream Oil and Gas Assets are optimized, sustainable, safe & reliable operations.

Chemical Characterization of Natural Gas Leaking from Abandoned Oil and Gas Wells in Western Pennsylvania.

The U.S. Environmental Protection Agency estimates that there are over 3.2 million abandoned wells in the United States. Studies conducted on gas emissions from abandoned wells have been limited to methane, a powerful greenhouse gas, due to concerns regarding climate change. However, volatile organic compounds (VOCs), including benzene, a known human carcinogen, are known to be associated with upstream oil and gas development and hence could also be released when methane is emitted to the atmosphere. In this investigation, we analyze gas from 48 abandoned wells in western Pennsylvania for fixed gases, light hydrocarbons, and VOCs and estimate associated emission rates. We demonstrate that (1) gas from abandoned wells contains VOCs, including benzene; (2) VOCs are emitted from abandoned wells, the magnitude of which depends on the flow rate and concentration of VOCs in the gas stream; and (3) nearly one-quarter of abandoned wells are located within 100 m of buildings, including residences, in Pennsylvania. Together, these observations indicate that further investigation is necessary to determine whether emissions from abandoned wells pose an inhalation risk to people living, working, or congregating near abandoned wells.

Data-Driven Analysis of Stimulation Treatments Using Association Rule Mining

Summary Effective analysis of data collected during the well’s operational cycle is crucial to well performance, economic evaluation, and good decision-making in the upstream oil industry. Generally, the analysis of huge volumes of data stored in databases is beyond the power of traditional methods, such as curve-fitting and statistical hypothesis testing. Data mining is the practice of analyzing large databases to identify patterns, anomalies, and correlations, within the data, leading to new, hidden, and valuable knowledge that would support decisions. This article proposes a data-driven methodology for analyzing the stimulation operations data in oil/gas wells to identify the underlying rules or patterns that lead to successful operations. Association rule mining (ARM) is used in this research for rule induction purposes. The proposed approach aims to mine the frequently occurring rules, within the collected database, that guarantee the success of stimulation operations with a high degree of confidence. Finally, the proposed approach is evaluated against a set of real data from an Iranian oil field. On the basis of past stimulation operations, these extracted rules show the conditions that are most likely to lead to a successful operation. The rules identified by the proposed approach are compared against the rules that can be generated by the decision tree (DT) technique using the same data set. As the reliability of the rules is controlled by setting the minimum thresholds on support and confidence, more significant and useful rules could be derived from ARM compared to the DT technique. Using the identified rules and generated information can support the operational decisions by assisting in the design of due stimulation jobs or in selecting the appropriate candidates for future operations.