Initial Oil Production Research Articles

Evaluation of the Pilot Test Effect of Steam Stimulation in Horizontal Wells of Sand Bodies 1-1308 in Bohai L Oilfield

In order to reduce the risk of large-scale thermal recovery of heavy oil in Bohai Oilfield, L Oilfield is selected to carry out horizontal well steam stimulation pilot tests. Previous studies have summarized the rationality of the injection parameters and initial production characteristics of this experiment, but the evaluation of its development effectiveness is still blank. Based on the study of the decline law of A23H well cold recovery using reservoir engineering methods, this article evaluates the initial production capacity, production increase effect, technical recoverable reserves, and throughput cycles of steam stimulation. The results show that the thermal recovery production of steam stimulation is three times that of cold recovery, which can significantly improve the production capacity of a single well. The initial daily oil production of two wells is 74m<sup>3</sup>/d and 90m<sup>3</sup>/d, respectively, which is 3.0 times and 3.6 times that of the initial production of cold recovery, exceeding the design level of the reservoir; The first round has the best yield increase effect, with an average daily oil increase of 31m<sup>3</sup>/d, and gradually decreasing thereafter. By the fifth round, it was only 13m<sup>3</sup>/d. In terms of yield increase multiples, each round can reach about 2 times; The technically recoverable reserves are 19.03 × 10<sup>4</sup>m<sup>3</sup>, requiring 8-9 rounds. Through this performance evaluation, we have strengthened our confidence in promoting the application of steam injection technology in Bohai Oilfield to achieve large-scale thermal recovery.

Optimizing estimated ultimate recovery in horizontal wells through data-driven analytics

The oil and gas industry has undergone significant changes in completion operation design and execution, largely due to the advancements in machine learning techniques. In our study, we analyzed a dataset of approximately 200 horizontal wells from the Wolfcamp formations, categorized into two groups based on productivity and classification as parent versus child (infill) wells. Using response surface methodology (RSM), a data analytics technique that models the relationship between explanatory and response variables with up to second-order polynomial terms, we illustrate how to optimize horizontal well performance, specifically focusing on Estimated Ultimate Recovery (EUR). We selected a pool of 5 input variables for analysis, including initial oil production of 180 days, injected fluid volume in barrels, number of perforations in each cluster, volume of Hydrochloric Acid injected during frack job in gallons, and volume of injected Linear Gel in gallons.The selections were made in collaboration with industry professionals and validated using data analytics-based methods that rank variable importance. By pinpointing potential strategies to achieve a globally optimal EUR through the adjustment of completion variables (perforations and hydrochloric acid should be set at their data-recorded maximum values of 7.69 and 10.82 on a logarithmic scale), the study aims to simplify the challenging task of maximizing EUR from producing wells, offering an additional avenue for estimating reserves. It emphasizes the adaptability of this approach in allowing different completion designs to be dynamically tailored for optimizing EUR, each with its unique set of inputs. Ultimately, these diverse designs can be synthesized through meta-analysis. In summary, the study provides a practical framework for EUR estimation, readily applicable by operators in unconventional exploration, representing a transformative milestone in the industry. The subsequent phase involves collecting additional data from this specific field area and employing a range of models to improve precision and specificity.

Oil Production Optimization Using Q-Learning Approach

This paper presents an approach for optimizing the oil recovery factor by determining initial oil production rates. The proposed method utilizes the Q-learning method and the reservoir simulator (Eclipse 100) to achieve the desired objective. The system identifies the most efficient initial oil production rates by conducting a sufficient number of iterations for various initial oil production rates. To validate the effectiveness of the proposed approach, a case study is conducted using a numerical reservoir model (SPE9) with simplified configurations of two producer wells and one injection well. The simulation results highlight the capabilities of the Q-learning method in assisting reservoir engineers by enhancing the recommended initial rates.

Comprehensive Study of Development Strategies for High-Pressure, Low-Permeability Reservoirs

Currently, there is no well-established framework for studying development patterns in high-pressure, low-permeability reservoirs. The key factors influencing development effect typically include the reservoir properties, well pattern, well spacing, and the rate of oil production. Reservoir A is a representative of this type of reservoir. Starting from its physical properties, a study of the development mechanism was conducted using the tNavigator (22.1) software. A total of 168 sets of numerical experiments were conducted, and 3D maps were innovatively created to optimize the development mode. Building upon the preferred mode, an exploration was carried out for the applicability of gas flooding and the optimization of water flooding schemes for such reservoirs. All experimental results were reasonably validated through Reservoir A. Furthermore, due to the high original pressure in such reservoirs, the injection of displacement media was challenging. Considering economic benefits simultaneously, a study was conducted to explore the rational utilization of natural energy. The research proved that for a reservoir with a permeability of about 10 mD, the suitable development scheme was five-point well pattern, a well spacing of 350 m, water–gas alternating flooding, and an initial oil production rate of 2%. When the reservoir underwent 8 months of depleted development, corresponding to a reduction in the reservoir pressure coefficient to 1.09, the development efficiency was relatively favorable. Over a 15-year production period, the oil recovery reached 29.98%, the water cut was 10.31%, and the reservoir pressure was maintained at around 67.18%. The geology of the newly discovered reservoir is not specific in the early stage of oilfield construction, and this research can help to determine a suitable development scheme.

A new method for the characterization of microcracks based on seepage characteristics

Microcracks are the main seepage channels and reservoir space for oil and gas in dense sandstone reservoirs, and the degree of development dominates the reservoir’s high and stable production capacity. A new method has been devised to address the lack of quantitative identification and characterization methods for microcrack networks. The method is based on core stress sensitivity, permeability anisotropy, and two-phase seepage rule testing. By improving upon the traditional black oil model, this method can accurately calculate the impact that microcracks of varying degrees of development have on the capacity of tight oil reservoirs. The study shows that 1) the higher the degree of microcrack development, the stronger the reservoir stress sensitivity and the greater the permeability anisotropy. As the degree of microcrack development increases, the irreducible water saturation decreases, the residual oil saturation gradually increases, and the oil–water two-phase co-infiltration zone becomes more extensive and smaller. The degree of microcrack development in tight reservoirs can be characterized based on the seepage characteristic parameters; 2) a microcrack characterization method and classification criteria have been established. It is based on stress sensitivity coefficients, permeability anisotropy parameters, and phase seepage characteristics in cores with different microcrack development degrees. For the first time, the method enables a macroscopic-level description of microcrack seepage; 3) numerical calculations show that the degree of microcrack development significantly affects the reservoir’s oil production and water production. The higher the degree of microcrack development, the higher the reservoir’s initial oil production and cumulative oil production. However, when the degree of microcrack development is too high, the microcracks are connected, thus exhibiting the nature of large fractures. This strengthens the bypassing communication effect and causes the microscopic inhomogeneity to strengthen, the oil production decreases rapidly, and water production increases quickly at the later stage. This research result enriches the reservoir microcrack characterization and evaluation system, which has essential theoretical guidance and practical significance for the rational and effective development of tight oil and tight sandstone gas.

INFLUENCE TECHNOLOGICAL PARAMETERS ON HYDRAULIC FRACTURING EFFICIENCY

Link for citation: Khizhniak G.P., Assane Dieng. Influence technological parameters on hydraulic fracturing efficiency. Bulletin of the Tomsk Polytechnic University. Geo Аssets Engineering, 2023, vol. 334, no. 6, рр.120-125. In Rus. Relevance. Hydraulic fracturing in production and injection wells is one of the effective method for enhancing oil recovery, involving low-permeability zones and interlayers in the development, a mechanism for a wider coverage of productive zones by waterflooding, which makes it possible to convert part of off-balance reserves into commercial ones. According to experts, the use of hydraulic fracturing can increase the oil and gas recovery factor by 10–15 %. Currently, most of the oil fields in the Perm Territory are at the final stage of development. These fields, as a rule, are characterized by non-draining zones with residual reserves and low well flow rates. Most of the remaining reserves of the fields are concentrated in low-permeability reservoirs with a high degree of heterogeneity and difficult fluid filtration. The increase in the productivity of wells of these production facilities is achieved through the use of various geological and technical measures. The main aim: to develop a methodology for predicting the oil production rate post-frac with parameters that influence more, taking into account geological and technological characteristics of the object. Objects: Kashirskiy and Podolskiy carbonate deposits on one of the Permian fields. Methods: correlation and regression analysis. Results. The hydraulic fracturing method is widely used to increase well productivity. Unfortunately, oil flow rates obtained in practice do not always correspond to preliminary calculations. Using the example of one of the fields in the Perm Territory, a method proposed that allows estimating the initial oil production rate after hydraulic fracturing using the values of the technological parameters of productive deposits and the methods of mathematical statistics. A good agreement between model and experimental results was obtained.

Design Optimization and Analysis of Tubing Head Spool for Surface Wellheads are used in the Oil and Gas Industry

The Tubing Head serves as the uppermost spool in a surface wellhead and is typically positioned above the production casing, which is the final string of pipe suspended within the well. It plays a vital role in various functions from well drilling to initial oil production. Tubing head spools have been employed in conventional surface wellheads for many years. However, the current design of the spool is characterized by its significant weight and bulkiness. While this design has proven its effectiveness in the field, there is a need for improvements in terms of size and shape. The primary objective of this study is to reduce the weight and modify the size and shape of the tubing head spool, specifically the 13-5/8”-10K Bottom X 7-1/16”-10K Top variant, utilizing Solidworks modelling and simulation techniques. By leveraging these tools, we aim to optimize the design, achieve weight reduction, and enhance the overall performance of the tubing head spool. The optimization process begins with a comprehensive analysis of the existing tubing head spool design to identify potential areas for improvement. This analysis includes evaluating the stress distribution, pressure containment capabilities, and material utilization of the spool. Various optimization techniques, such as finite element analysis (FEA) are employed to simulate and analyse different design scenarios. We successfully, achieved weight reduction of 5.16% in raw forging and 14.45% in finish part.

A semi-analytical rate-transient analysis model for light oil reservoirs exhibiting reservoir heterogeneity and multiphase flow

Rate-transient analysis (RTA) has been widely applied to extract estimates of reservoir/hydraulic fracture properties. However, the majority of RTA techniques can lead to misdiagnosis of reservoir/fracture information when the reservoir exhibits reservoir heterogeneity and multiphase flow simultaneously. This work proposes a practical-yet-rigorous method to decouple the effects of reservoir heterogeneity and multiphase flow during TLF, and improve the evaluation of reservoir/fracture properties. A new, general, semi-analytical model is proposed that explicitly accounts for multiphase flow, fractal-based reservoir heterogeneity, anomalous diffusion, and pressure-dependent fluid properties. This is achieved by introducing a new Boltzmann-type transformation, the exponent of which includes reservoir heterogeneity and anomalous diffusion. In order to decouple the effects of reservoir heterogeneity and multiphase flow during TLF, the modified Boltzmann variable allows the conversion of three partial differential equations (PDE's) (i.e., oil, gas and water diffusion equations) into ordinary differential equations (ODE's) that are easily solved using the Runge-Kutta (RK) method. A modified time-power-law plot is also proposed to estimate the reservoir and fracture properties, recognizing that the classical square-root-of-time-plot is no longer valid when various reservoir complexities are exhibited simultaneously. Using the slope of the straight line on the modified time-power-law plot, the linear flow parameter can be estimated with more confidence. Moreover, because of the new Boltzmann-type transformation, reservoir and fracture properties can be derived more efficiently without the need for defining complex pseudo-variable transformations. Using the new semi-analytical model, the effects of multiphase flow, reservoir heterogeneity and anomalous diffusion on rate-decline behavior are evaluated. For the case of approximately constant flowing pressure, multiphase flow impacts initial oil rate, which is a function of oil relative permeability and well flowing pressure. However, multiphase flow has a minor effect on the oil production decline exponent. Reservoir heterogeneity/anomalous diffusion affect both the initial oil production rate and production decline exponent. The production decline exponent constant is a function of reservoir heterogeneity/anomalous diffusion only. The practical significance of this work is the advancement of RTA techniques to allow for more complex reservoir scenarios, leading to more accurate production forecasting and better-informed capital planning.

Research and Successful Application of the Diverted Fracturing Technology of Spontaneously Selecting Geologic Sweet Spots in Thin Interbedded Formation in Baikouquan Field

Baikouquan oil field is composed of multiple interbedded, thin, low-permeability layers, which are required to vertically fracture multiple layers and to create complex fractures for economic development. However, conventional fracture technologies create a single, simple fracture, having poor feasibility for this field. Therefore, we conducted research on fracturing technology by spontaneously selecting geologic sweet spots based on diversion. This technology can vertically fracture the thin layers one by one and horizontally divert the fracture to non-depleted areas. Firstly, a triaxial diverted fracturing experiment approach was setup, and then diverted fracturing experiments were carried out to verify the feasibility of diverted fracturing and to study the fracture geometry and the law of diversion. Next, experiments were carried out to evaluate the performance of the diversion agents. The valuated properties comprise the diversion pressure, stability time, and degradation based on which to optimize the selection of the diversion agents. Finally, the fracturing technology was applied to well b21004 of Baikouquan oil field, and post-frac performance was evaluated. The experimental results show that multiple and complex fractures are realized through temporary plugging. Diversion performance evaluation tests show that a 4 wt% concentration of 1–5 mm granules + 20/60 mesh powder and a 3 wt% concentration of 1–7 mm granules + 20/60 mesh powder + fiber can hold up enough pressure to force the fracture to divert. The field treating pressure curve shows that there is a 3–10 MPa pressure increase when there are pump diversion agents, which is a clear sign of fracture diversion. Plugging the fracture mouth gives a faster and a higher incremental pressure. Before this fracturing, the well had almost stopped oil production. After the stimulation, the initial oil production rate became 20 + t/d, which shows the effectiveness of this fracturing technology for Baikouquan oil field.

The paradox of increasing initial oil production but faster decline rates in fracking the Bakken Shale: Implications for long term productivity of tight oil plays

In the US, tight oil is the largest source of liquid hydrocarbons and has enabled the country to become the world's largest oil producer. The estimated ultimate recovery (EUR) and rate of production decline are key metrics in the evaluation of the future productivity of tight oil wells. We chose the Bakken Shale because of its high quality, publicly available data. Traditionally, well operators have estimated the EUR for each well from the initial production (IP), using empirical type curves to extrapolate to the ultimate production. From 2015 to 2018 the IP of the average Bakken well increased by approximately 50%. This increase resulted in claims by operators and in the academic literature that more intense hydraulic fracturing was increasing the average EUR of the Bakken play. At the same time, other observers claimed the wells declined much more rapidly than previous wells. This faster decline provided evidence for lower ultimate production from newer wells. The aim of this study was to understand the origin of these seemingly conflicting observations. A physics-based, scaling model was used to predict production from horizontal multi-stage fractured wells. The model for oil recovery is based on pressure diffusion through fractured porous media. The model assumes that the rock is incompressible, the permeability and oil saturation are constant, the water is incompressible, and the viscosity is slowly varying with space. The scaling model was applied to 13,444 wells. The EUR and terminal decline rate (TDR) were estimated from fitting production to our scaling model. Our study found that implementation of more intensive hydraulic fracturing resulted in higher IP and steeper terminal-production declines. Recently published results estimating the total production from the Bakken that include increased lifetime production commensurate with observed increases in average IP, significantly overestimate the long-term production potential of tight oil, both in the US and globally.

Petrophysical heterogeneity of the early Cretaceous Alamein dolomite reservoir from North Razzak oil field, Egypt integrating well logs, core measurements, and machine learning approach

Capturing the petrophysical heterogeneities within a reservoir has a critical influence on reservoir deliverability as well as field development programs. In this study, we report a comprehensive petrophysical evaluation of the oil-producing Aptian Alamein dolomite reservoir from the North Razzak field, Western Desert of Egypt. Integration of wireline logs and routine core analysis indicates that the Alamein reservoir has an extremely wide range of porosity (1–23%) and permeability (0.01–7000 mD), contributed by the early diagenetic dolomitization history and complex distribution of vugs. Petrophysical assessment by reservoir quality index (RQI) and flow zone indicator (FZI) infers that the megaporous rock types offer very good to excellent reservoir qualities and macroporosity dominated intervals are of fair to good quality. Further, we developed a permeability prediction model in this challenging carbonate rock based on Random Forest (RF) regression, and tested its efficacy and generalizability by well-defined performance metrics. The RF-based algorithm provided a more confident permeability prediction (R2 = 0.937) compared to conventional methods. Based on the petrophysical attributes; six distinct petrofacies (PF) associations are identified. PF-1, PF-3, and PF-5 provide excellent reservoir qualities with superlative storage capacity and hydraulic flow potential contributed by connected vugs, while the microporosity-dominated impervious PF-2 and PF-4 intervals act as intra-reservoir permeability barriers. We suggest that the higher initial oil production rate was mainly contributed by the larger connected pores and vuggy spaces. As reservoir pressure drops, hydrocarbon flows restrict to the smaller pores causing accelerated production weakening. Based on this comprehensive analysis, a suitable drilling and completion strategy is recommended for the future reservoir development program.

ELECTRICAL POWER UNIT OF THE TRANSFORMER OIL CENTRIFUGAL CLEANING UNIT

Problem. Cleaning transformer oil is one of the important engineering tasks, whose solution is associated with significant material and energy expenditure. Due to the increase in electricity consumption at modern automobile companies (firms, organizations, service stations, etc.), the load on transformer substations increases and the requirements for reliability of electrical and electronic devices become more complicated. This, in turn, leads to the problem of cleaning and recycling of transformer oil. Goal. The goal is the research and development of an efficient unit for centrifugal cleaning of transformer oil with a drive control system that provides automation of the start and braking mode of the drive. Methodology. Analytical methods of research, methods of the theory of electric machines and electric drives are used, as well as the methods of calculating electric circuits. Also, methods of analysis of circuits and control of power electronics devices, principles of operation and methods of control of static converters are used. Results. The structural scheme of the unit for cleaning transformer oil is developed. The calculations of the main elements of the power block of the transformer oil cleaning unit are performed. The block diagram of the voltage converter with frequency f = 50 Hz to alternating voltage with frequency f = 400 Hz is developed. Control circuits of the electric drive of the centrifugal separator are chosen. The analysis of operation of electric drive control circuits is carried out and the principles of their work concerning two components are considered: the regulated rectifier and the inverter. Originality. The scheme of the converter of alternating three-phase current with voltage of 220 V and frequency of 50 Hz, into alternating three-phase current with voltage of 220 V and frequency of 400 Hz is developed. This frequency, in addition to providing the necessary characteristics of the oil separator, allows you to develop a converter device of a relatively small weight and volume, and also provides its high reliability. Practical value. Utilizing the used transformer oil in this way will solve several problems at once. It is possible to reduce the initial production of transformer oil. The issue of waste oil disposal is being resolved leading to the solution of the environmental aspect of this problem. All this will reduce the cost of oil poured into transformers and the operating cost of transformer substations.

Unlocking flow pathways in complex carbonate reservoirs: Benefits of an integrated subsurface study from the Cretaceous Mauddud Formation, North Kuwait

Despite its long production history (since 1958) and extensive reservoir stimulation by water injection, the Mauddud reservoir of the Sabiriyah field (SAMA) in northern Kuwait has been plagued by relatively disappointing oil production increase, low oil-by-water replacement ratios, and early water-breakthrough observations. The work described in this paper indicates that reservoir complexity and associated permeability heterogeneity are at the root cause of this and are the result of the interplay between sedimentology, diagenesis and the structural evolution of the area.A multi-disciplinary study involving structural geology, sedimentology, diagenesis, reservoir engineering and geomechanics identified the geological processes responsible for the development of principal high-permeability (High-K) elements in SAMA. Their 3D distribution has been characterized and reservoir property ranges have been established, based on integrated evaluation of static (e.g., seismic, core, borehole image, wireline logs, and drilling information such as losses) and dynamic information (e.g., production and injection logging tools, well test information, pressure data, historical production data and tracer information). Feedback loops between geological realizations and dynamic simulations allowed the testing of various concepts and property ranges with learnings implemented in updates of the geological realizations. This approach increases the confidence level in the conceptual geological models.Three principal plumbing elements contribute to the reservoir and property heterogeneity in the SAMA reservoir. Firstly, relatively thin (one to several decimeters) cemented zones characterized by low matrix porosity but significant secondary vuggy and fracture porosity with high permeability occur in two distinct stratigraphic intervals in the reservoir. These intervals occur near sequence boundaries when the carbonates likely experienced brief periods of exposure. They are interpreted to be cemented cycle tops formed during meteoric diagenesis and represent key flow zones for the initial hydrocarbon production as well as for later high-rate production of formation water and injected water, as identified by production/injection logging tools. Faults and associated fault (damage) zones with abundant fractures are the second key plumbing element. Core recovery and observations from wells located closely to a fault zone identified from detailed seismic interpretation highlight the occurrence of abundant fractures. Tracer information clearly identifies faults as preferential migration pathways between injector and producer wells. Thirdly, induced fracture growth near injectors is an important process in the context of High K development. Hall plots identified that injectivity often increases near injectors after a certain period of injection. Geomechanical analysis suggests that induced fracture growth is plausible due to reduction in total horizontal stress due to the combined effect of depletion and water-injection-induced cooling of the reservoir.Reservoir simulations validate the requirement of presence of these three key elements in the plumbing diagram. Yet, dynamic sensitivity testing shows that the three processes each have a variable impact on flow in the reservoir, depending on local factors such as the nearby presence of faults and the development of the cemented cycle tops. Dynamic simulations further indicate that (1) porosity in the cemented cycle tops is likely low, in line with core observations and out of sync with upscaled porosities and (2) lateral extent of individual cemented cycle tops is in the order of few hundred meters, but final connectivity is enhanced by the stacking of different cemented cycle tops and their concentration in two distinct zones in the Mauddud.Armed with the insight from core analyses and dynamic model results, recommendations are made to improve oil production in SAMA: (1) inject away from the zones and faults, and (2) reduce the injection pressure, thus limiting the likelihood of “new” induced fractures and faults forming that may connect to “old” geologic fracture and faults and cause early-water-breakthrough and thus ineffective oil sweep. Reservoir stimulation via matrix injection, rather than under fracturing conditions, may reduce the initial oil production boost but will most likely lead to significantly better ultimate recovery over the long life of SAMA.

Reservoir formation conditions and key technologies for exploration and development in Qingcheng large oilfield

The Qingcheng oilfield, the largest shale oil field in China, was discovered in 2019 in source rock of Chang 7 Member of Mesozoic Yanchang Formation, Changqing Oilfield in Ordos Basin, with newly increased proven geological reserves of 358 million tons, predicted geological reserves of 693 million tons, and a total of 1.051 billion tons of shale oil resources. This achieves a historic breakthrough in exploration of shale oil in Chang 7 Member. In recent years, focusing on key issues, such as whether there develop sweet spots in source rock, whether commercial oil production capacity can be formed, and whether scale-effective development can be achieved, studies about geological conditions for shale oil accumulation have been continuously carried out, key supporting technologies have been developed, and a series of theoretical innovations and technological breakthroughs have been achieved in oil exploration in source rocks. The results indicate that shale oil accumulation in Chang 7 Member is controlled by following factors. Firstly, lacustrine black shale, dark mudstone and other high-quality source rocks lay a material foundation for shale oil formation. Secondly, sandy deposits intercalated within black shale and dark mudstones are exploration sweet spots, and sandbody combination types are controlled by morphology of bottom of the lacustrine basin. Thirdly, reservoir properties are good due to development of micro-nano pore throats. Finally, reservoirs with high oil saturation and high gas-oil ratio are formed due to high-intensity oil charging in source rock. Effective matching of multiple factors is a key for shale oil accumulation in Chang 7 Member in Ordos Basin. Through innovation of key supporting technologies, exploration and development technologies for shale oil are developed, and substantial breakthrough on exploration and development of shale oil is realized. The first application of logging-seismic combination technology in loess plateau improves significantly quality of 3D seismic data, which effectively guides prediction of sandy sweet spots. Three-quality well logging technology is used for further evaluation of geological and engineering sweet spots of shale oil. With volumetric fracturing technology based on precise segmentation of long horizontal wells, initial daily oil production of individual well is increased from previously 10 tons to more than 18 tons. The exploration breakthrough in source rocks in Chang 7 Member in Qingcheng oilfield provides an important resource base for the second accelerated development of Changqing Oilfield. It is predicated that oil production from shale in Chang 7 Member in Qingcheng oilfield will reach three million tons in 2022 and five million tons in 2025.

Prescriptive Analytics Aids Completion Optimization in Unconventionals

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 195311, “Prescriptive Analytics for Completion Optimization in Unconventional Resources,” by Mehrdad Gharib Shirangi, SPE, Yagna Oruganti, and Thomas Wilson, Baker Hughes, et al., prepared for the 2019 SPE Western Regional Meeting, San Jose, California, 23–26 April. The paper has not been peer reviewed. This paper discusses a prescriptive analytics framework to optimize completions in the Permian Basin. The methodology involves data processing, ingestion into databases, and data cleansing; application of automated machine learning (AutoML) to generate an accurate machine-learning model; and numerical optimization of decision parameters to minimize an economic objective. Constructing a Pareto front enabled decision makers to select a strategy that minimized cost without sacrificing too much of the initial 12-month oil production. Overview A typical way to assess the performance of an oil well is to compute the total cost per barrel of oil produced at ultimate recovery. However, in cash-constrained operating environments, including many unconventional plays, other measures, such as $/bbl of oil produced in the first year, may also be used. Because of the intensive nature of running detailed physics-based models to optimize decision parameters related to wellbore placement and well completion, a pure simulation-based optimization strategy typically is not feasible. The complete paper describes a data-driven machine-learning model that was selected to predict the oil production profile of a new well in an unconventional play because of its efficiency and its ability to directly learn from abundant historical data. Data analytics are typically applied in three phases: Descriptive analytics, which makes sense of data Predictive analytics, which helps build an accurate machine-learning model to forecast a performance measure or an output on the basis of input parameters Prescriptive analytics, which helps to develop recommendations to improve performance Input parameters to the machine-learning model presented in the complete paper included system parameters (e.g., well location and trajectory, existence and type of artificial lift) and decision parameters (e.g., number of stages, amount of stimulation material). The authors used an optimization algorithm to explore systematically the space of decision parameters. Training data included drilling, completion, and production data from previous wells in the same formation. Initial input features were extracted and prepared on the basis of domain expertise. The AutoML process searched automatically among various machine-learning algorithms (e.g., neural networks, random forest) to find the best algorithm and the best associated hyper-parameters. A multiobjective optimization process was implemented to optimize the 12-month oil production (Qoil) and the completion cost divided by Qoil simultaneously. The methodology was applied to a real case in the Permian Basin, in collaboration with Diamondback Energy. The results demonstrated that the two objectives were conflicting. The construction of the Pareto front, which showed a set of optimal solutions, provided a visual tradeoff for decision makers and enabled them to select a strategy that minimized cost without sacrificing much of the initial 12-month oil production. The predictive model was then used to optimize the completion design of new wells to either maximize the cumulative oil produced, or minimize the completion cost per barrel of oil produced, in the first year.

The Enoch Field, Block 16/13a, UK North Sea

Abstract The Enoch Field is located in the South Viking Graben and straddles the UK/Norway median line with 80% of the field in the UK and 20% in Norway. Enoch produces undersaturated oil from the Early Eocene-age Flugga Sandstone Member of the Sele Formation. Hydrocarbons have been trapped by a combination of compaction-related dip closure and sand pinchout. The current stock tank oil initially in place estimate is c. 42 MMbbl with expected ultimate recovery of 11.5 MMbbl. The field was brought onstream in May 2007 via a single horizontal subsea gas-lifted well tied back to the Brae Alpha platform. Initial oil production rates were c. 11 800 bopd. The field is currently in decline and in December 2018 production was c. 1800 bopd with 80% water-cut. Cumulative oil production to the end of 2018 was 10.581 MMbbl.

Investigation of the Interaction of Surfactant at Variable Salinity with Permian Basin Rock Samples: Completion Enhancement and Application for Enhanced Oil Recovery

Summary Adding a surfactant to completion fluids has been widely applied to improve the initial oil production from unconventional liquid reservoirs (ULRs). However, very limited research has been conducted to understand the interactions between surfactants and salt in ULRs, and to identify the effect of ζ-potential (ZP), interfacial tension (IFT), and contact angle (CA) on oil recovery through surfactant/salt-assisted spontaneous imbibition (SSASI). This study investigates the interactions of surfactant and salinity in different ULR lithologies in west Texas (WT), USA, and determines the relationship between the experimental parameters and oil recovery to provide potential screening criteria for completion-fluid design. With the combination of numerous chemicals at different concentrations and nine salinity levels, more than 50 variations of aqueous-phase solution were blended. Also, heterogeneous ULR rock samples of the WT formation with two different dominant lithologies, quartz-rich (WT QR) and carbonate-rich (WT CR), were selected. All combinations of fluid were used for ZP, IFT, and CA measurements, and some were selected for SSASI experiments with timely computed-tomography (CT) scans. Then, all experimental results were plotted against the oil recovery factor (RF) to determine the most impactful parameter on oil recovery and to obtain knowledge regarding desired conditions of salinity for surfactant-added completion fluid. The effect of salinity on ZP, IFT, and CA had a similar trend for all fluid cases. With increasing salinity, the magnitude of ZP decreased to nearly 0 mV, meaning either a thin electrical double layer (EDL) or none surrounding the rock particles. Surfactant and salt reduced IFT strongly until it reached the critical salt concentration (CSC) of 30,000 ppm, and then reduction occurred gradually and slowly. Surface wettability was different for the two rock types, and the ability to alter wettability varied by the condition of fluids. Wettability alteration occurred with the presence of both surfactant and salt, but most effectively at salinity between 20,000 and 30,000 ppm. Also, the wettability of the quartz-rich rock type showed more water-wetting surface compared with the carbonate-rich rock type. Out of all the experimental parameters, CA showed the strongest effect on oil recovery. Only 5 to 10% of the oil was produced when the rock surface was oil-wet, but the oil recovery increased up to 25% when the surface became intermediate-wet. Finally, when the rock surface became water-wet, 25 to 40% of the oil was produced from SSASI. Consequently, on the basis of this investigation of surfactant/salt interactions, we determined the salinity of 20,000 to 33,000 ppm to be the most favorable condition for salt/surfactant-added completion fluids, which effectively reduces IFT and yields the strongest wettability alteration. Understanding the interactions between salt and surfactant and their behaviors in different types of reservoirs is essential when analyzing the reusability or dilution of high-salinity produced water and successfully designing completion fluids for ULRs. The significance of this study is the ability to determine the most synergetic condition of blended-salt/surfactant solutions and identify the parameter with the greatest impact on oil recovery in ULRs to provide surfactant-screening criteria. Furthermore, we demonstrate economic and environmental benefits by using produced water and fresh water for completion activities.

Natural fractures in tight-oil sandstones: A case study of the Upper Triassic Yanchang Formation in the southwestern Ordos Basin, China

Natural fractures are important storage spaces and fluid-flow channels in tight-oil sandstones. Intraformational open fractures are the major channels for fluid flow in tight-oil sandstones. Small faults may provide fluid-flow channels across different layers. According to analogous outcrops, cores, and borehole image logs, small faults and intraformational open fractures are developed in the tight-oil sandstones of the Upper Triassic Yanchang Formation in the southwestern Ordos Basin, China. Among them, high dip-angle intraformational open fractures are the most abundant. Northeast-southwest–trending fractures are the principal fractures for fluid flow because that is the present-day maximum horizontal compressive stress direction. Combined with production data, horizontal wells, striking normal to or at a large angle relative to the major flow pathways, are beneficial for tight-oil production improvement. Fractures with high dip angles are the main factor that influences initial oil production. Linkage and tip damage zones are more favorable for oil production improvement than wall damage zones. This study provides an example of natural fracture characterization and unravels fracture contributions to reservoir physical properties and oil production of tight-oil sandstones, which could provide a geological basis for oil exploration and development in tight sandstones.

ПРОГНОЗИРОВАНИЕ КОЭФФИЦИЕНТА ПРОДУКТИВНОСТИ СКВАЖИН С БОКОВЫМ СТВОЛОМ (НА ПРИМЕРЕ УНЬВИНСКОГО МЕСТОРОЖДЕНИЯ)

Актуальность. Многие месторождения Соликамской депрессии Пермского края характеризуются завершающей стадией разработки и имеют высокий коэффициент извлечения нефти, близкий к проектному, высокую обводненность добываемой продукции, ухудшение технико-экономических показателей добычи. Для выполнения проектных показателей на месторождениях применяются различные методы повышения нефтеотдачи. Анализ их применения показывает, что наибольший средний прирост начального дебита скважин по нефти достигается путем зарезки боковых стволов. При обосновании расположения бокового ствола в интервале продуктивного пласта одним из основных показателей дальнейшей эффективности работы скважины является начальный коэффициент продуктивности скважины по нефти. Цель: разработать методику прогнозирования коэффициента продуктивности по нефти скважин с боковым стволом с учетом геолого-технологических характеристик объекта. Объекты: бобриковские терригенные отложения Уньвинского месторождения Соликамской депрессии. Методы: корреляционный и регрессионный анализ, основанный на данных геофизических и гидродинамических исследований скважин, значениях фильтрационно-емкостных свойств пласта, физико-химических свойств нефти, а также геолого-технологических показателях. Результаты. Разработанная методика позволяет оценивать значения коэффициента продуктивности по нефти скважин с боковым стволом на основе результатов геофизических и гидродинамических исследований скважин, значений фильтрационно-емкостных свойств пласта, физико-химических свойств нефти, а также геолого-технологических показателей с помощью пошагового регрессионного анализа и разделения исходных данных значений коэффициента продуктивности по нефти на классы на основе его зависимости от коэффициента детерминации. Установлено, что при значениях Кпрод.н≥10 основное влияние на коэффициент продуктивности по нефти скважин с боковыми стволами оказывают технологические показатели – зенитный угол α бокового ствола в интервале продуктивного пласта и длина Lст ствола скважины в пласте, что говорит о возможности регулирования процесса довыработки запасов нефти изменением этих параметров.

Development of Surrogate models for CSI probabilistic production forecast of a heavy oil field

The aim of this work is to present the development of a Surrogate Reservoir Model capable of accurately predicting cumulative oil production of a heavy oil field in Mexico considering variables with uncertainty. Five numerical models of wells were considered for the numerical model of the field. Four input uncertain variables (the dead oil viscosity with temperature, the reservoir pressure, the reservoir permeability and oil sand thickness hydraulically connected to the well) were selected as the ones with more impact on the initial hot oil production rate according to an analytical production prediction model. The central composite experimental design technique was selected to capture the maximum amount of information from the model response with a minimum number of reservoir models simulations. Twenty five runs were built to be run with the STARS simulator for each well type on the reservoir model. The results show that Surrogate Reservoir Models are an ideal tool to perform real-time probabilistic production forecasting of the reservoir.