Drill Stem Test Research Articles

Case Study: Understanding H2S Occurrence: Bakken Production Using Sulfur Isotopes

_ Souring—or H2S generation—in the Bakken petroleum system (BPS) production is becoming problematic for oil producers and pipeline operators because of the sporadic occurrence and associated economic and HSE impacts. Paradoxically, crude oil produced from the tight Middle Bakken (MB) and underlying Three Forks (TF) reservoirs of the BPS has historically been light (40 °API to 50 °API) with low sulfur content (<0.2 wt.%), typically exhibiting nonexistent to low (<10 parts per million) H2S concentrations. Additionally, neither the MB nor the TF reservoirs have public records indicating the presence of H2S during drillstem tests (DST). However, based on previous work performed by the University of North Dakota Energy & Environmental Research Center (EERC), the frequency of H2S occurrence in BPS wells has increased from 2010 to 2023. Even though the observed H2S increases correlate with larger, multistage well stimulation and completion practices in the BPS, the unclear geographical and temporal trends make the exact mechanisms responsible for souring an open research question. At least five known mechanisms can potentially lead to H2S occurrence in the oil production stream of BPS wells, including: 1. Thermochemical sulfate reduction (TSR) 2. Bacterial sulfate reduction (BSR) 3. Source rock generation 4. Migration from deeper or shallower H2S reservoirs 5. Geochemical mechanisms related to reservoir stimulation work (Table 1). Understanding the mechanisms of H2S generation might reduce the risk of souring in new wells and enable more effective mitigation and management strategies in the wells already producing H2S. Samples Used in the Study This study is focused on oil and gas operations in the North Dakota portion of the Williston Basin and the H2S occurrences in the BPS, which includes two main oil-producing reservoirs: the MB and the TF. In the simplified stratigraphic sequence, the BPS comprises three distinctive lithofacies. From deepest to shallowest, those lithofacies are the Lower Bakken Shale (LBS), the MB reservoir, and the Upper Bakken Shale (UBS). Underlying the BPS is the TF, the upper part of which is the oil-rich TF reservoir, considered part of the BPS. The UBS and LBS are the source rocks for the oil in MB and TF reservoirs and consist of black, organic-rich, siliciclastic mudstones (i.e., shale). Directly overlying the BPS is the Madison Group, a carbonate-dominated Mississippian section that is subdivided into three formations—the Lodgepole (LP), Mission Canyon (MC), and Charles. The Birdbear Formation lies beneath the TF and on top of the Duperow Formation. Both the Duperow and Birdbear Formations produce oil and are dominated by carbonate deposits of shallow marine limestone and dolostones. A sampling program was developed to investigate areas of the BPS with varying levels of souring in the production stream and multiple organic-rich formations representing potential source rocks, including the UBS, LBS, LP, and MC. The samples were collected from locations and formations with different lithologies and maturity levels. Over 70 sour wells were identified for H2S sampling in western North Dakota.

Unraveling the hidden relationships between seismic multiattributes, well-dynamic data, and Brazilian pre-salt carbonate reservoirs productivity: A shallow versus deep machine-learning approach

During the initial phases of an E&P project, the most reliable data on the reservoir’s deliverability are acquired via drill stem tests (DST), which provide the productivity per flow unit whenever production logging tool data are available. However, DSTs are restricted to a few kilometers, whereas seismic data cover large areas. The integration of these data has been challenging, particularly due to the difference in scale between them. So, a new workflow to determine the relationship between poststack seismic attributes and reservoir productivity using classic supervised (shallow) and deep-learning regression algorithms was developed. The DST parameters were predicted over the entire seismic cube, which can be extremely valuable for the decision-making process. The data set is from the Brazilian deep-water presalt carbonate reservoirs of the Mero Field, which is a well-explored area with a plethora of test and production data. It is adjacent to an underexplored Central Libra appraisal plan area, which is covered by the same seismic survey. Thus, any relationships between seismic attributes and well productivity data observed at the Mero Field are extrapolated to the adjacent underexplored area. Ten seismic attributes and DST data from 10 wells of the Mero Field were used to train shallow and deep-learning supervised regression algorithms for the prediction of flow capacity and productivity index seismic cubes. Twenty development wells (blind tests) were used for the assessment of our predictive models. The highest percentage of correct predictions at the blind test wells (85%) was obtained with random forest regression using six attributes derived from a spectrally balanced full-stack volume, and neither amplitude-variation-with-offset nor inversion data were needed. Deep learning provided lower performance (75%) at a higher computational cost. It demonstrated a new reservoir derisking tool that can be used for project optimization in areas covered by the same seismic survey.

Determination of the Main Production Factors and Production Predictions of Test Wells in the Offshore Tight Oil Reservoirs in the L Formation of the Beibu Basin Using Multivariate Statistical Methods

This study addresses the challenge of rapidly and accurately predicting the production of test wells in offshore tight oil reservoirs, specifically within the L Formation of the Beibu Basin. This challenge is particularly pronounced in situations where drill stem tests are limited and evaluating each untested well layer is difficult. To achieve this objective, we analyzed fifteen typical test wells in the L Formation, taking into account both geological and engineering factors. Initially, Pearson correlation analysis, partial correlation analysis, and grey relational analysis were used to identify the main production factors. Based on these analyses, two types of production prediction models were developed: one employing the comprehensive production index method and the other utilizing the production coefficient method. The research identified effective permeability, porosity, oil saturation, and shale content as the main production factors for the test wells in the study area. The model verification results showed that the comprehensive production index model performs effectively for the L Formation, with an average prediction error of 20.40% compared to the actual production values. This research is significant for optimizing and stabilizing production in tight oil reservoirs.

Permeability Upscaling Conversion Based on Reservoir Classification

Deep and ultra-deep reservoirs are characterized by low porosity and permeability, pronounced heterogeneity, and complex pore structures, complicating permeability evaluations. Permeability, directly influencing the fluid production capacity of reservoirs, is a key parameter in comprehensive reservoir assessments. In the X Depression, low-porosity and low-permeability formations present highly discrete and variable core data points for porosity and permeability, rendering single-variable regression models ineffective. Consequently, accurately representing permeability in heterogeneous reservoirs proves challenging. In the following study, lithological and physical property data are integrated with mercury injection data to analyze pore structure types. The formation flow zone index (FZI) is utilized to differentiate reservoir types, and permeability is calculated based on core porosity–permeability relationships from logging data for each flow unit. Subsequently, the average permeability for each flow unit is computed according to reservoir classification, followed by a weighted average according to effective thickness. This approach transforms logging permeability into drill stem test permeability. Unlike traditional point-by-point averaging methods, this approach incorporates reservoir thickness and heterogeneity, making it more suitable for complex reservoir environments and resulting in more reasonable conversion outcomes.

2D INVERSION MODELING OF OIL AND GAS BASINS USING GRAVITY DATA IN TAMBELANG DISTRICT

Pertamina Hulu Energi discovered a new source of oil and gas reserves in Tambelang, Bekasi Regency, which was named East Pondok Aren (EPN-001). These oil and gas reserves have great potential based on the oil flow test in the second Drill Stem Test. The drill data needs to be correlated with other supporting data such as geophysical methods to ensure the accuracy. Therefore, this research was conducted to examine the subsurface structure of oil and gas reserves in EPN-001 through 2D inversion modeling using the gravity method. Gravity satellite data was taken via the GGMPlus website with a total of 23,898 data in the form of gravity disturbance, geoid, and topography, so only terrain and bouguer corrections were carried out to get the Complete Bouguer Anomaly value. The research results show low anomaly values from -0.4463 – (-0.0339) mGal which are thought to be associated with alluvium lithology and the Lower Cibulakan Formation. In the 2D model, it can be seen that the drilling point in the Lower Cibulakan Formation layer has a density contrast value of -0.002 – 0.001 g/cc at a depth of 2590 m, and is known to be a reservoir that stores hydrocarbon reserves in the research area.

Bridging the gap: Integrating static and dynamic data for improved permeability modeling and super k zone detection in vuggy reservoirs

Permeability modeling in fractured and vuggy reservoirs presents significant challenges, especially in carbonate reservoirs like Brazil’s Barra Velha Formation. The interpretation of vug properties is often subject to misconceptions. It is common to mistakenly consider vugs as part of the matrix, attributing uniform porosity and permeability properties. Alternatively, they are sometimes regarded as fractures, attempting to replicate the influence on permeability enhancement. However, vugs exhibit distinct behavior compared to fractures. Their characteristics are contingent upon factors such as geometry, size, and their relationship with the matrix. Existing methods often overlook the substantial impact of vuggy porosity, leading to inadequate representation of permeability values obtained from core plug measurements or downhole static data, such as Nuclear Magnetic Resonance (NMR) logs. In contrast, dynamic data derived from drill-stem tests (DSTs) and inferred from the Productivity Index (J) provide a more holistic view of the reservoir’s permeability, yet typically yielding a single permeability value for each interpreted interval. This research introduces a novel methodology that addresses these challenges by integrating static and dynamic data, with a primary focus on vuggy porosity using a permeability indicator from a dynamic source. A key innovation lies in the development of a method for estimating total permeability in vuggy intervals, accounting for the effects of vugs and calibrating permeability with dynamic data such as J, DST and Production Logging Tests (PLT). We substantiated the impact of vugs on the augmentation of permeability and production through the application of a localized reservoir simulation model around a key well. Two sensitivity analyses were conducted, one employing a grid representing matrix permeability and another incorporating total permeability with adjustments accounting for the influence of vugs. Additionally, we present two approaches for estimating vuggy porosity: one based on acoustic WellBore Image (WBI) and the second through image segmentation, which can be applied universally across different wellbore image formats. Furthermore, this study explores the concept of superkzones, representing intervals with exceptionally high permeability. The partitioning coefficient (CP), quantifying the relationship between vuggy porosity and total porosity, is employed to generate a probability curve for the occurrence of superkzones in intervals lacking production data. This curve accounts for critical factors such as pressure drop and fluid viscosity, providing a more comprehensive understanding of reservoir behavior. Through a comprehensive case study, our research aims to shed light on the intricate permeability characteristics of the Barra Velha Formation, while identifying the presence of superkzones. The proposed methodologies offer a bridge between static and dynamic data, resulting in a continuous permeability curve that aligns more closely with production data. Ultimately, this work contributes valuable insights for reservoir management and the production strategies optimization in complex carbonate reservoirs within the Santos Basin.

Predicting the thermal regime of the Po Plain subsurface (Italy) using geostatistical modeling constrained by legacy wells

Italy boasts a long history of hydrocarbon exploration. The Po Basin, in particular, has been extensively explored due to its peculiar geological setting, arising from the convergence of the Southern Alps and Northern Apennines. Because of this, substantial subsurface data have been collected and made publicly available. Today, data from past oil and gas exploration campaigns can find new life in decarbonization programs, especially for geothermal exploration. Geothermal data on the Po Basin, including bottom hole temperature (BHT) and drill stem test (DST) records, play a crucial role in understanding the thermal state of the subsurface, and can therefore be employed in the exploration of geothermal resources. This study presents a 3D model of the thermal regime in the Po Basin based on the analysis of legacy hydrocarbon wells. Geostatistical models of subsurface temperatures are produced via direct sequential simulations that consider: (i) the overall geothermal gradient across the region, (ii) anisotropy in the temperature field revealed by variogram analysis, and (iii) temperature data in the surrounding geological volumes. A base-case model of expected temperature values and associated conditional variance are thus generated from which depth-to-the-isotherm maps were extracted for temperatures in the low-enthalpy range (<100 °C). The study confirms that promising thermal anomalies are mapped in the Ferrara Arc and the buried Southern Alps. These areas offer opportunities for new developments and the repurposing of depleted oil wells for district heating. Additionally, the findings highlight other areas in the Po Plain (e.g., Emilian Arc) where there exists more subtle geothermal potential for further exploration and development.

Solutions to Complex Well-Testing Challenges Aid Offshore Black Sea Gasfield Development

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 215123, “Frontiering Ultradeep Water Gas Field Development, Offshore Black Sea, Turkey: Solutions to Complex Well-Testing Challenges and Proving Production Potential,” by Coşan Ayan, SPE, Suat Aktepe, and Koscal Cig, Turkish Petroleum, et al. The paper has not been peer reviewed. _ Increasing demand for reliable energy resources has led to an increased exploration activity for untapped hydrocarbon resources in deep water. The recently discovered, fast-tracked Sakarya offshore natural gasfield development is a prime example. This paper describes dynamic reservoir characterization considerations, challenges, and engineering solutions to derisk field-development decisions, confirmed by a well-testing campaign in a complex setting with no tolerance for failure. Sakarya Field The Sakarya field is approximately 170 km north of the Turkish coast in the Black Sea at 2117 m (Fig. 1). The natural gas field was discovered in August 2020 and is estimated to have potential natural gas reserves of 11 Tcf of lean gas, making it the largest gas reserve discovered in the Turkish Exclusive Economic Zone as well as the Black Sea. In October 2020, a second discovery was made in the lower sections of Tuna 1, which increased the potential recoverable reserve estimate to 14.3 Tcf of lean gas. The discovery was found at the deeper part of the well, where an additional 30 m of gas pay was encountered in the sandstone reservoir of the Late Miocene. Further, the drilling of the exploratory well Amasra 1, 40 km north of the Sakarya field, led to the discovery of 4.7 Tcf of gas in June 2021, and increased the potential recoverable cumulative natural gas reserves to 19 Tcf. The first gas production from the Sakarya gas field began in 2023 into the Turkish grid from the completed wells of the first phase of the project. To accelerate the time to first gas production, it was deemed necessary to flow-test the reservoirs to acquire critical reservoir information, assess production potential and completions efficiency, and reduce the number of wells. This was achieved by drilling and testing several appraisal wells with multiple target intervals that will be used later as producers. Well-Completion Strategy Affecting Well-Test Program Formation-failure studies and wireline formation testing data have shown that these weak reservoirs are prone to sand production. As a result, downhole sand-exclusion completions are necessary. Gas permeabilities are good, with core-measured air permeabilities in the range of 1–1000 md. The reservoir pressure varies from 4,200 to 5,800 psi, depending on depth. Reservoir temperatures are relatively low, in the range of 25–60°C. Lower Completion Installation Sequences. After drilling, the main section was completed with 9⅞-in. 62.8-lbm/ft production casing. The selected interval from openhole logs and formation test results was perforated and overbalanced by individual runs of a tubing-conveyed perforation (TCP) system. On the second run, sump packers with direct wrap screens across the interval were installed and gravel was pumped. After the lower completion was in place and the drillstem test (DST) had been conducted, another part of the lower completion across the upper interval was installed and flow-tested. After completing all DST well tests, the well was suspended with the lower completion system in place, ready for installation of the upper completion with intelligent flow-control valves and permanent gauges.

A Method to Identify Pore Fluids in Heterogeneous Conglomerate Reservoirs Using a Nuclear Magnetic Resonance Log with Oil-Based Mud Invasion

Summary Nuclear magnetic resonance (NMR) logging has been extensively utilized for identifying pore fluids in recent years. However, after oil-based mud (OBM) invasion, OBM filtrate partially takes the place of the original fluid in the reservoir and the morphology of the NMR T2 (transverse relaxation time) spectrum changes. OBM invasion makes it difficult to identify the formation fluid using routine NMR fluid identification methods. In this study, we took heterogeneous conglomerate formation in the northwestern Junggar Basin as a case study and carried out core experiments under four conditions (viz., water-saturated, OBM displacing water, oil-saturated, and OBM displacing oil) and simulated the states of OBM invasion into water and hydrocarbon-bearing formation. Comparative analysis finds that when the OBM invades the water layer, the movable peak of the T2 spectrum primarily reflects the bulk relaxation characteristics of OBM filtrate, whereas when the OBM invades into the oil layer, the T2 spectrum may exhibit a three-peak distribution, where the first peak mainly indicates irreducible water, the second peak reflects OBM filtrate, and the third peak primarily reflects nondisplaced oil. To facilitate fluid identification, two T2 cutoffs are adopted to divide the T2 spectrum into three segments, and combined with the T2 geometric average, a fluid identification factor (ifluid) is proposed. Finally, identification criteria for reservoir type are established on the NMR logging and drillstem test data. The field application verifies the reliability of the proposed methods. These methods realize the identification of oil layers under OBM drilling and guide the subsequent production and development of oil reservoirs.

Exploration history of the igneous reservoirs of the Rio Grande Valley (Mendoza), Neuquén Basin (Argentina)

Abstract Oil seeps related to igneous rocks in the Neuquén Basin have been known since pre-Hispanic times (sixteenth century) and have been explored in the southern Mendoza province since the late nineteenth century. In the 1980s, YPF (Yacimientos Petrolíferos Fiscales) began the exploration of igneous rocks as hydrocarbon reservoirs in the Río Grande Valley area. The possible productivity of these ‘unconventional’ reservoirs was recognized by studying outcrops and well data of sills and dykes emplaced in different formations of the fold and thrust belt of the northern Neuquén Basin. Mud-logging control and evaluations with drill stem tests (DST) were decisive to define these reservoirs as prospective. From petrographical reports on samples from outcrops and cores, six lithological types could be distinguished in the igneous units of this region. Recent works confirm that this volcanism belongs to two predominant cycles: from the late Oligocene to the Miocene (‘Molle’) and from the Middle to upper Miocene (‘Huincán’). Although in igneous reservoirs it is difficult to forecast the estimated ultimate recovery (EUR), sills that crosscut the source rocks of the Vaca Muerta and Agrio formations demonstrate surprisingly high production rates, although the number of wells for the complete development is always difficult to establish.

Dynamic Simulation Platform Aids Deep Transient Tests, Well-Control Safety

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 215454, “Enhancing Well-Control Safety With Dynamic Well-Control Cloud Solutions: Case Studies of Successful Deep Transient Tests in Southeast Asia,” by M. Ashraf Abu Talib, SPE, M. Shahril Ahmad Kassim, and Izral Izarruddin Marzuki, SPE, Petronas, et al. The paper has not been peer reviewed. _ The complete paper addresses challenges related to well control and highlights the successful implementation of deep transient tests (DTT) in an offshore well performed with the help of a dynamic well-control simulation platform. The paper aims to provide insights into the prejob simulation process, which ensured a safer operation from a well-control perspective. Additionally, a comparison between simulated and actual sensor measurements during the DTT operation is presented. DTT DTT is a formation-testing (FT) method that allows pressure transient tests that reach deeper into the formation compared with conventional interval pressure transient tests (IPTT). DTT enables the testing of formations with higher permeability, greater thickness, and lower viscosity and real-time measurement of crucial parameters. During a DTT, formation fluid is pumped from the reservoir; upon stopping the pump, the formation pressure begins to recover as fluid further from the wellbore replaces the extracted fluid. By analyzing the resulting pressure transient, properties such as formation permeability, permeability anisotropy, and other characteristics can be determined. DTT allows for a better understanding of reservoir characteristics and rock heterogeneity. When properly designed and executed, DTT can reveal potential baffles and boundaries within the radius of investigation. A further advantage of DTT over drillstem tests (DST) is its minimal fluid flow, which allows for the attainment of objectives while contributing to the United Nations sustainable development goals. In DTT operations, the FT tool is connected to the drillpipe through a circulating sub and a slip joint. The circulating sub plays a critical role in DTT operations because it enables the continuous mixing of pumped formation fluid with circulated mud and facilitates its transportation to the surface (Fig. 1). Typically, a constant circulation rate ranging from 100 to 250 gal/min is maintained. During circulation, the annular preventer is closed and the mud/hydrocarbon mixture is directed through the choke line to the mud/gas separator (MGS) once it reaches the surface. No formation fluids are flared during DTT operations. Instead, the circulated oil is retained in the mud and only small amounts of gas are vented. By use of a slip joint, the FT remains anchored to the borehole wall. A high-resolution pressure gauge is used to capture and interpret even minor pressure fluctuations during the pressure transient buildup.

Technology Focus: Well Testing (February 2024)

Standing alone as the shortest month of the year, February also features JPT’s Well Testing Technology Focus, reviewing the latest industry publications on the subject. Well testing has enjoyed a recent uptick in activity and interest as operators continually realize the value in understanding and monitoring the dynamic performance of their reservoirs. Whether it pertains to the deliverability of conventional oil and gas or the storage potential for carbon capture and storage, large-scale dynamic data remains one of the more coveted pieces to the subsurface puzzle. There is no silver bullet for reservoir characterization. Instead, proper characterization will always be the result of integrating static and dynamic data, collected at varying scales, with a macro geological understanding. Technology facilitates the collection of the aforementioned data. With the latest technologies pushing limits of what can be achieved, subsurface engineers must rigorously evaluate what reservoir characterization techniques and tools are suited for project objectives. Formation testing (FT) platforms provide many options for operators to get a first look at dynamic reservoir performance and nearly always precede a well test. After digesting the alphabet soup of acronyms, so many FT options exist that one may encounter what psychologists refer to as “choice overload.” FT objectives also may begin to overlap with objectives traditionally reserved for drillstem tests (DSTs), narrowing a long-standing technology gap. The current advances in FT tools are exciting, and using FT tools to perform a “mini-DST” makes for brilliant marketing. However, “mini” could mean up to 10,000 times less produced volume, which undoubtedly affects objectives thought to overlap. Subsurface complexity is mitigated by defining clear objectives and executing data-collection programs to reduce uncertainty. Caution should be taken in selecting how to dynamically test your reservoirs. Regardless of how advanced hardware becomes, achievable objectives always will be dependent on key factors such as rock and fluid properties, reservoir geometry, and local regulatory and environmental considerations. This month’s papers highlight ongoing developments from different segments of the well-testing discipline. Dive into valuable lessons learned from a frontier carbon capture, use, and storage project, backed by an impressively sized data set and an in‑depth review of multiphase effects. This case study covers differing saturations around the wellbore region and fluid types in operations and should have global applications. Learn about the limitations and potential pitfalls of nonisothermal effects in pressure transient analysis, which pose challenges in the reservoir characterization of geothermal wells. Sensitivities to thermal effects on reservoir rock properties provide intriguing insights. Completion efficiency also may be affected by thermal effects, resulting in additional pressure drop at sandface. Finally, catch up on one of the weapons most recently added to the well-testing arsenal with powerful new FT tools that feature industry improvements for greater flexibility and improved data reliability. Recommended additional reading at OnePetro: www.onepetro.org. OTC 32610 Multiphase Flowmeter Comparison in a Complex Field by Mohammed Alqahtani, Saudi Aramco, et al. IPTC 23050 Frequently Asked Questions in the Interval Pressure Transient Test and What Is Next With Deep Transient Test by Saifon Daungkaew, SLB, et al.

Geochemical Approaches Assist Production Allocation of Commingled Fluids

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 205130, “The Application of Petroleum Geochemical Methods to Production Allocation of Commingled Fluids,” by Richard Patience, Mark Bastow, and Martin Fowler, Applied Petroleum Technology, et al. The paper has not been peer reviewed. _ Geochemical-based methods for production monitoring and allocation are much lower-cost than use of production logging tools because no additional rig time or extra personnel are required at the well site. Additionally, no intervention to the production of hydrocarbons from a well is required, reducing operational risk. The complete paper summarizes these approaches and provides examples and describes a best practice that avoids a one-size-fits-all approach. Introduction Production allocation from petroleum geochemistry is defined here as the quantitative determination of the amount or portion of a commingled fluid to be assigned to two or more individual fluid sources at a particular moment in time based on fluid chemistry. It requires knowledge of the original chemical compositions of each of the fluids before mixing (referred to here as the “end members”) and the ability to identify statistically valid differences in their chemistries. The fluid may be oil, gas, or water. The concept is illustrated in Fig. 1a by mixing colors to represent the end members and commingled fluid. Production monitoring, in contrast, is the analysis of a time series of production fluids from the same source. This is demonstrated in Fig. 1b, where a change in chemistry can be observed between Days 60 and 100. Two data points at the same time are duplicates, proving that the change in chemistry is real and not an artifact. It is generally qualitative to semiquantitative in comparison with production allocation. Production allocation, therefore, is inherently more complex, in terms of both the sample requirements and data treatment. Allocation is the main focus of this paper. Allocation Sampling Strategies For a production allocation project, the three following distinct stages require samples: Stage 1: Can Contributing End Members Be Distinguished? In the initial stage, a determination must be made regarding whether end member reservoirs contributing to production can be distinguished based on their chemical composition. End Members From Conventional Plays. These typically are flowed samples from drillstem tests, bottomhole samples from wireline tools, or production tests, usually taken during the drilling of exploration or appraisal wells. Several issues must be considered when assessing the usefulness of such samples: - Are the end member samples representative of the reservoir as a whole? - Is the end member sample contaminated with organic compounds from drilling fluid? - When were the end members taken, how were they stored, and has there been significant alteration of the composition of the sample as a result?

Chemical and Carbon Isotope Composition Proves Effective as Gas Diagnostic Tool

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 209992, “Gas Chemical and Carbon Isotope Composition as a Diagnostic Tool for Energy,” by Zainab Almubarak, SPE, Mohammad Alrowaie, and Feng Lu, Saudi Aramco, et al. The paper has not been peer reviewed. _ Chemical and carbon isotopic compositions of produced gases are useful tools to monitor gas production and to assess their origin, thermal maturity, and migration. In the complete paper, the authors present different geochemical approaches to assess the origin of gases and thermal maturity and to evaluate the effect of adsorption on shale gas during production. Introduction Carbon isotope type curves constructed for compounds from methane through n-pentane can be used to group gases into distinct families and correlate them to their source rocks. Large variations in carbon isotope ratios exist among the natural gas compounds, which are caused by isotopic fractionation between the sedimentary organic matter (kerogen) and each individual hydrocarbon compound. During the generation of hydrocarbons from kerogen, cracking of 12C-12C bonds requires slightly less energy than 13C-12C bonds. Thus, hydrocarbons will be enriched in 12C relative to the kerogen. Methane, which contains only one carbon atom, shows the greatest fractionation and will have the most negative δ13C value (most enriched in 12C). Ethane through pentane show progressively less fractionation (less negative δ13C values), with the latter usually having a δ13C value close to that of kerogen (and associated oil). The magnitude of the fractionation effect will vary depending on the type of kerogen (i.e., Type I, II, IIS, or III), the temperature during hydrocarbon generation, and the adsorption/desorption effect. Thus, gases generated from different source rocks often have distinctive carbon isotope type curves. In shale gas (unconventional reservoirs), two different types of gases coexist—free gas and adsorbed gas. Free gas occurs in natural fractures and matrix pores, whereas adsorbed gas is noted on the surface of pores. During the early stages of production, free gas accounts for most produced gas. The adsorbed gas starts in mid-late stages but maintains high and stable production. In this study, the authors use carbon isotopic compositions of light hydrocarbons (C1–C5) to assess origin and thermal maturity and to compare different gases derived from unconventional reservoirs. Moreover, carbon isotopes are used to assess migration paths and to monitor gas production in unconventional shale gas reservoirs. The gas samples were collected periodically from the same interval to monitor any isotope variation and evaluate the effect of gas adsorption. Methods Pressurized samples of natural gas were collected from conventional and unconventional reservoirs through production tests, drillstem tests, or downhole samplers and analyzed for chemical composition. For the conventional study, a total of 13 gas samples were collected from different reservoirs (A, B, C, D, and J): four gas samples from Reservoir A, two gas samples from Reservoir B, three gas samples from Reservoir C, three gas samples from Reservoir D, and one gas sample from Reservoir J. Gases derived from Reservoirs A, B, and J are younger and shallower than gases derived from Reservoirs C and D (older and deeper). For the unconventional study, seven gas samples were collected periodically from the same shale interval (Reservoir W) from the same well (Well Y) on different dates to monitor any isotope variation.

The Comparation of Water Saturation Approaches to Reveal a Low Resistivity Reservoir Potential Case in Gumai Formation, South Sumatra Basin

The LRLC reservoir zone has been identified in SN-3 well, at the DAP-1 interval on Gumai Formation. This interval has a low resistivity value from 3-5 ohm.m and the drill stem test (DST) results show oil with gas without water. This study is objected to identify the causes of LRLC reservoir in gumai formation and finding a suitable sw calculation method. Some data such as well logs, reports, cores, and XRD are used to calculate petrophysical parameters such as Vsh, Phie, and Sw, and would be validated by DST data. Water saturation (Sw) calculations from Archie and the CEC method (Waxman Smits, Dual Water, Juhasz) were performed and the results were compared. The results showed that the main cause of the DAP-1 interval LRLC zone was the presence of clay minerals consisting of mixed layers (Illite/smectite). These clay minerals will be associated with high cation exchange capacity (CEC) values, with the value 70 (meq/100g), which can increase conductivity and reduce resistivity values. Based on lumping the more optimistic results of sw calculation from Waxman Smits Sw method (Sw based on CEC method). The DST data on the SN-3 well does not have water test data, so the calculation of the Sw value that is close to the Swirr value is considered the most suitable Sw for the low resistivity reservoir conditions of the Gumai Formation in the study area. The best practice for low resistivity reservoir for suitable petrophysical calculation is necessary to pay attention to the rock lithology conditions, the presence of mineral clay, and determining suitable Sw appropriate to the reservoir conditions

Convective Versus Conductive Heat Flow in The Central Alberta Part Of The Western Canada Sedimentary Basin

Alberta, Canada, T6H 5X2. A detailed study of the hydrogeological and geothermal regimes in the Phanerozoic sequence of the Western Canada Sedimentary Basin was carried out for the Swan Hills and Cold Lake areas in central Alberta. The study was based on the examination, processing and interpretation of information from 6276 wells distributed over a total area of 39,500 km². The information processed refers to stratigraphic picks, chemistry of formation waters, drill stem tests and bottom hole temperatures. As a result, every stratigraphic unit is defined in terms of geometry and lithology, and characterized by appropriate hydraulic and thermal parameters. A sequence of eight major aquifer groups separated by eight aquitards and two aquicludes was identified. The fluid flow in the Paleozoic aquifers is mainly horizontal and regional in nature, being driven by the difference in hydraulic potential between the high areas in the foothills and the lowland areas in the prairies. The fluid flow in the Cretaceous aquifers is of regional to intermediate type, with a significant downward component. The fluid flow in the aquitards is vertical. The very low permeability of the strata is reflected in flow velocities on the order of magnitude of 1 cm/a and less. Dimensional analysis of heat transport processes in each hydrostratigraphic unit shows that convective heat transfer is negligible with respect to conductive heat transfer. The respective values of the Peclet number for heat flow in porous media areas are less than 10-2. In the Swan Hills and Cold Lakes areas the flow of the terrestrial heat flux from the crystalline Precambrian basement of the sedimentary basin to the atmosphere is controlled by the geometry and the changes in the thermal properties of the formations in the basin. The geothermal gradients for individual layers vary from 17 mK/m for sandstone units to 42 mK/m for shales. The integral geothermal gradient of the entire sedimentary column varies between 22 mK/m and 36 mK/m. The areal distribution of the integral geothermal gradient shows a strong correlation with stratigraphy and lithology.

Numerical Simulation of Pore Pressure Change Caused by Hydrocarbon Generation in Chezhen Sag and Its Influence on Hydrocarbon Accumulation

The pore fluid pressure is important for the generation, migration, and accumulation of hydrocarbons. The Chezhen Sag region in the Bohai Bay Basin is typically characterized by pore fluid overpressure, which is the difference between the pore fluid pressure and the hydrostatic pore pressure. The formation mechanisms of pore overpressure and the accumulation regularity of the “upper source-lower reservoir” type in this region remain unknown. In order to investigate these problems, based on the existing seismic, logging data, and regional tectonic stress environment, we established a two-dimensional finite element model to simulate the fluid–solid coupling processes in the Chegu 25 block of the Chezhen depression. We calculated the abnormal overpressure generated at the source rock during hydrocarbon generation and the processes of hydrocarbon migration and accumulation along the faults and analyzed the dynamic conditions of the hydrocarbon downward accumulation. The results showed that overpressure could accelerate the migration of hydrocarbon and improve the efficiency of hydrocarbon accumulation. When the overpressure was too large, tensile fractures and shear fractures could occur, resulting in hydrocarbon dissipation, and changing the results of the oil and gas accumulation. The overpressure at the source rock was mainly caused by hydrocarbon generation, while the overpressure at the reservoir was primarily created by unbalanced compaction. As the dominant channel of hydrocarbon migration that exists, overpressure will change the direction and path of hydrocarbon migration in the fault. Therefore, the high permeability of the fault and the existence of pore fluid overpressure can explain the “upper source-lower reservoir” hydrocarbon accumulation model strongly explained the high permeability of faults and the presence of overpressure. The simulated overpressure results were also in good agreement with the mud weight equivalent overpressure and the drill stem tests (DSTs).

Deep low-salinity groundwater in sedimentary basins: petrophysical methods from a case study in Somalia

Oil and gas exploration data for the Northern Somalia and Horn of Africa region have been utilised for deep freshwater resources exploration. This unique geophysical and petrophysical dataset is integrated into a regional hydrogeological study and it allows for targeting of unmapped and unknown deep aquifers that would otherwise be beyond the conventional reach of the groundwater sector. The database includes open-hole well logging surveys (resistivity, gamma ray, and spontaneous potential), mud logging and drill stem test (DST) data. The results from the data analysis are combined with the geological interpretation to assess the freshwater potential of each mapped hydrostratigraphic unit in the region. The results highlight the presence of several previously unknown deep low-to-medium salinity (<9 g/L total dissolved solids (TDS)) aquifers within the Jurassic to Eocene units, including the Adigrat, Hamanlei, Gabredarre, Gumburo, Jessoma, and Auradu formations. With tested intervals of water containing less than 3.8 g/L total dissolved solids, the Auradu, Jessoma, and Gumburo formations are the most promising deep freshwater aquifers. Additional results on the analysis of groundwater parameters, such as hydraulic head, provide the basis for further groundwater modelling. The results show that the method has good potential, in particular for use in drought-stricken areas of arid regions. Ultimately, the results from this region have global significance, as the method can provide a new means of boosting fresh groundwater resources in water-poor regions, and supporting sustainable development and utilization of the resources in the medium and long term.

Integrating 4D Data Into Dynamic Model Improves Johan Sverdrup Field Development

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 209541, “Integration of Johan Sverdrup PRM 4D Data Into the Dynamic Model,” by Monica A. Calvert, Yuri Tsaplin, and Hans P. Hansen, TotalEnergies. The paper has not been peer reviewed. _ The Johan Sverdrup field permanent reservoir monitoring (PRM) system now has recorded two surveys documenting the progression of the waterflood since production and injection began in October 2019, revealing a clear 4D signal linked to the increase in water saturation. The 4D signals have been used to help guide updates within the reservoir model, providing a better understanding of how the field development is progressing. Field Background and PRM System The giant Johan Sverdrup oil field was discovered in 2010 in the North Sea approximately 150 km west of Stavanger. The field is laterally extensive, covering 200 km2 and consisting primarily of Upper Jurassic intra-Draupne sandstone and Upper Triassic-Lower Jurassic Statfjord sandstones in a low relief structure. The reservoir is characterized by excellent porosity and permeability, with drillstem tests showing permeabilities of up to 70 darcies with good communication over long distances and across faults. The oil is undersaturated with a low gas/oil ratio and is normally pressured, with slight depletion from a regional drawdown. Reservoir thickness varies across the field, with the intra-Draupne sandstone ranging from 5 to 40 m. The primary drainage strategy includes initial waterflooding to be supplemented by water-alternating-gas injection at the end of the oil-production plateau. The full field development consists of 64 wells, both platform and subsea. Producers are placed on the structural highs with water injectors placed on the flanks below the initial oil/water contact (OWC). Because of full voidage replacement by water injection, reservoir pressure is expected to stay fairly constant during field life. Johan Sverdrup is the first oil field to have a PRM system installed before production startup. The PRM system is a key component of the reservoir-monitoring and data-acquisition plan and was installed in two stages in 2019 and 2020 (Fig. 1). Yearly monitor surveys are planned to monitor waterflood development. The first seismic acquisition in 2019, referred to as PRM0, covered the initial first stage of installation on the northern part of the field. Stage two of the installation was completed in 2020, and two monitor surveys have since been acquired, covering the entire field, in 2020 (PRM1) and 2021 (PRM2). Feasibility studies show that a 4D response would be detectable within the reservoir. The increase in water saturation caused by water injection and upward movement of the OWC yields an increase in acoustic impedance, or hardening, in the reservoir. For the 4D analysis, the main seismic surfaces used were the Top Aasgard formation, the Top Viking group (which contains the Draupne formation), and the Intra Upper Triassic Unconformity (IUTU). The acoustic impedance increase measured in the 4D seismic data is compared with water-saturation changes within the reservoir model. Differences between the two can highlight areas within the reservoir model that require updating.

Distal accumulation of leaked gas from deep overpressured zone：the case of the Yanan Sag, Qiongdongnan Basin, South China Sea

In the overpressured Yanan Sag of Qiongdongnan Basin, South China Sea, four structures contain varying gas volumes despite overall similarities in geological conditions. One notable difference, however, is their varying pressure characteristics. We investigated the nature and cause of the overpressure as well as its relation to natural gas migration-accumulation in the four structures. Well logs, drill-stem tests (DSTs), and mud weights, reveal two zones of overpressure in the YC21-1 and YC26-1 structures that contain no economic gas reservoirs. There is one zone of overpressure in the YC13-1 structure, whereas the YC13-4 structure is hydrostatically pressured. Cross-plot analysis of density and sonic logs indicates a mild to moderate overpressure section in the Neogene strata, interpreted as resulting from disequilibrium compaction and clay diagenesis.The Pliocene to Quaternary is considered to be a key period for strong overpressure formation in the Yanan Sag. Fast subsidence and burial may have induced intense gas generation by maturation and vertical compaction disequilibrium in the Oligocene strata of the central Yanan Sag. The resulting high pressure would have been transferred to the Oligocene reservoirs in the YC21-1 and YC26-1 structures in the slope belt. Fluid-inclusion homogenization temperature (Th) in combination with modeled burial curves indicates that gas filled the four structures during this period, suggesting that gas migration was associated with overpressure. Fluid-inclusion phase reflecting gas saturation and abnormal excursion of vitrinite reflectance (%Ro) suggest that leakage related to caprock fracturing resulted in gas accumulation failure in the high-pressure YC21-1 and YC26-1 structures. 13C depletion of methane in the YC13-1 and YC13-4 structures away from the sag center suggests that the current gases probably result from gas exsolution from formation waters. These gases are high-to over-mature, and thus were mainly derived from the deeper, central Yanan Sag rather than the local source rocks. Therefore, we infer that the gas leaked from the deep high-pressure zone in the sag center, then migrated in solution until a point at which PVT conditions would allow exsolution. Subsequently, the free gas would have migrated into the normally pressured reservoirs in the slope belts where it finally accumulated. Compared to the YC13-4 structure, the overlying Neogene mudstones in the YC13-1 structure are overpressured, which may serve to increase the seal capacity and explain the higher gas reserves in this area.