bluuebunny/crossref_metadata_2025 huggingface dataset:
Production Optimization: Understanding and Solving Scale Formation in Mature Gas Wells
Authors: Schenkel Mara Lis , Irazuzta Verónica Laura , Candia Gisella Anahi , Scianca Norah , Aguero Sergio David
Published: October 2020

Since 2015, scale problems have appeared when gas production decreased below 30 Mm3/day and wells could not evacuate liquid and solids to the surface due to liquid loading. Scale depositions were found in casing and tubing at different depths close to Quintuco Formation perforations. During 2019, more than 30 wells were mechanically cleaned using slick line to remove scale every 30 days approximately. This paper describes the study of the origin of scale in gas wells producing from multiple formations and the chemical technology applied to solve this problem in the mature urban field Centenario (Neuquén - Argentina).

Core and water analysis were performed to study the scale phenomenon at the productive formations and to determine the compatibility between fracturing and formation waters. In addition, it established the scale origin and served to detect further wells susceptible to suffer scaling problems. Scale is produced in the casing, not in the formation, due to changes of pressure and temperature related to the expansion of gas and changes in water mix compatibility at Quintuco perforations depth. Due to the field location, subsurface safety valves were installed in the tubing to prevent possible blowouts. Thus, capillary string for product injection was discarded. A proven chemical technology for oil wells-encapsulated scale inhibitors-was adapted to treat gas wells aiming for a treatment duration of three months. The method consisted of a mechanical clean-up followed by a batch treatment of encapsulated product with water and, finally, a slick line run to ensure it reached the bottom-hole. The chemical treatment pilot was carried out in 6 wells.

Candidates were selected based on abnormal production decline, scales showed after slickline intervention, favorable response after mechanical clean-up, and high intervention frequency. The pilot held in 2019 showed an increase in gas rate production of 12 Mm3/day on average representing 40% of well production, high stability in gas production and a reduction of slickline intervention frequency. The duration of the treatment was initially estimated according to the liquid rate of the well and the product concentration used. During 2020 the pilot will be expanded to 32 wells in the field.

Solid scale inhibitor for gas wells is relatively new in the industry and there is not much bibliography about application and results in this type of wells. This paper describes the methods used for scale characterization, the prediction of its formation in gas wells, the selection method for scale inhibitors, the product application technique to the wells and the results obtained in the pilot, demonstrating its technical and economic feasibility for field use.
Hybrid Well Pattern to Unlock Yan’an Tight Gas Reservoir, Ordos Basin, China
Authors: Wang Xiangzeng , Zhang Lei , Zhang Tao , Qiao Xiangyang , Wang Yongke , Zhao Xisen , Li Xiangfang
Published: October 2020

Yan’an gas field is a typical tight sandstone reservoir with multiple gas layers, large vertical span, variable size of effective sandbody, high heterogeneity, and complex surface ground environment. Due to the depositional background including both continental and marine face, the tight gas reservoir shows marginal characteristics with low porosity/permeability, thin sandbody thickness and low lateral continuity. If the field is recovered by the current mainstream technology "horizontal drilling+multi-stages hydraulic fracturing", the subsurface reserves will not be controlled fully, resulting in low economic benefit. With over a decade of practice, a cost-effective hybrid well pattern adapted to each layer and each region was formed which shows its efficiency in development of Yan’an gas field. In the hybrid well pattern, directional (vertical) well is adopted to fully control the reserves of the four main gas-bearing layers, while horizontal well is adopted to maximize the production for the reserve-enriched layers. Unlike the uniform well spacing for the marine tight gas reservoir, the well spacing in Yan’an gas field is non-uniform to adapt the strong heterogeneity in terms of storage and percolation, and the methodology to quantify the well spacing according to the local reservoir property was discussed in detail. To decrease the sand-lost drilling risk in such a low sand-continuity reservoir, the strategy named "sand recognition while drilling" is proposed for the well placement. The mathematical models for designing the directional (vertical) wells and horizontal wells are also presented in this work. In addition, the non-technical factors such as loess plateau topography and coal/water/oil resources overlay give large difficulties to open the well site and extended reach wells are required, and the criterion in selection different types of well group was given mathematically as well. The above factors in constraint the well pattern are summarized with property constraint, local constraint, macro constraint and environment constraint. The hybrid well pattern successfully unlocked and maximized the marginal gas field.
Long Term, Periodic Aerial Surveys Cost Effectively Mitigate Methane Emissions
Authors: Sridharan Sri , Lazarus Aaron , Reese Carrie , Wetherley Erin , Bushko Katrina , Berman Elena
Published: October 2020

Results of multiple years of periodic aerial methane surveys over Pioneer Natural Resources’ operations footprint, comprising approximately 680,000 acres in the Permian basin, are presented, including impacts to operational efficiency, cost, and methane emissions mitigation. Aerial methane detection was performed using a light-aircraft mounted, integrated methane imaging spectrometer. Geo-referenced methane emissions data combined with real-time geo-referenced optical imagery provided accurate methane localization and source attribution. Ground inspection teams used optical gas imaging technology to validate the aerial results and dispatch repair teams. Externally validated leak quantification provided by the spectrometer further allowed accurate measurement of methane mitigation. Aerial methane inspections of nearly 10,000 operations sites per survey, including wells, tank batteries, and all associated equipment, are reported for multiple years of periodic surveys. The data shows a complete picture of the most significant methane emissions from the Pioneer operations footprint over consecutive years and has proven beneficialinvaluable for enhancing operational efficiency. Based on the data, Pioneer has been able to identify the areas of highest impact and focus operational resources on those improvements. Surveys identified types of emission sources that can be addressed immediately within Pioneer operations and areas where Pioneer would need to work with others to improve overall gas takeaway challenges in the Permian basin. Furthermore, Pioneer has reduced leak detection and repair (LDAR) costs significantly by reducing both driving time and ground-based inspection time. We estimate more than 2500 work hours and 1000 driving hours, were saved by each aerial survey. Between 2016 and 2018, the company's methane intensity has declined approximately 41%. Aerial survey results have allowed Pioneer to significantly reduce methane emissions while simultaneously improving safety and efficiency, reducing costs, and reducing vehicle traffic. To our knowledge, this is the first multi-year, comprehensive, aerial periodic methane survey of an entire upstream oil and gas operation's footprint. We're now able to report on the benefits of this paradigm shift away from conventional LDAR surveys. Although the challenge of reducing methane emissions can be daunting, the results from aerial monitoring show that with a technology and data-driven approach, operators can significantly reduce emissions while simultaneously reducing costs and improving operational efficiency.
Treatment of Losses Based on Root Cause and Fracture Width Analysis
Authors: Zhang Jianguo , Sant Randall , Majidi Reza , Edwards Stephen , Rodgerson Alan , Last Nigel
Published: October 2020

Lost circulation (LC) is extremely costly to many drilling operations due to loss of mud and productive time. Significant industry resources have been devoted to providing recommendations for both preventing and curing losses. These comprise bridging particles, settable pills and a focus on the better understanding, measurement and control of downhole pressures. The industry has also started to examine the relationship between downhole losses and fracture geometry. However, there has been very limited verification and utilization of such effort.

Knowledge of the loss mechanism(s), location of the thief zone and fracture geometry is fundamental for understanding and treating losses effectively. The proposed method introduces a systematic approach for diagnosing lost circulation into potential root cause(s) by utilizing up to twenty-two diagnostic indicators. This allows the most appropriate treatments to be mapped to the suspected root cause. This technique supports the creation of preventative strategies during well planning. For example, if induced fractures are identified as the most likely root cause in the planning stage, then a wellbore strengthening formulation based on the fracture width estimation is recommended.

A proper treatment can be designed based on the fracture width analysis as the data becomes invaluable in determining optimum sealing and effective treatment for losses into conductive natural fractures/faults. In case of loss events, the fracture width can be estimated based upon loss rate, the mud rheology, bottom hole pressure and pore pressure.

Field experiences demonstrate that natural and induced fractures are the two most common root causes of losses. For induced fractures, fracture width usually develops beyond 3000-micron (µm) once losses have occurred and the preventive lost circulation materials (LCM) have not then worked effectively. If the bottom hole pressures can be kept below fracture propagation limits (or far-field minimum horizontal stress), then induced fractures will not cause significant volume of losses. The drilling induced fractures can be modelled by using in-situ stresses, well trajectory, bottom hole pressure, geothermal and mud temperature information.
Data-Driven Rate Optimization Under Geologic Uncertainty
Authors: Sen Deepthi , Chen Hongquan , Datta-Gupta Akhil , Kwon Joseph , Mishra Srikanta
Published: October 2020

We propose a novel approach for rate optimization during a waterflood under geologic uncertainty in reservoir properties such as permeability and porosity. The traditional approach typically involves several runs of the forward simulator. This may not scale well when the optimization is to be performed at the full field-level and over multiple geologic realizations. A machine-learning (ML) based approach which is quick and scalable for rate optimization over multiple geologic realizations is proposed instead. The training data for the model is generated by running the forward simulator with randomly assigned well rates using multiple geologic realizations. A reduced order representation of the permeability heterogeneity in each of the realizations is derived using a grid connectivity transformation (GCT). This step involves finding basis functions corresponding to the different modal frequencies of the grid connectivity represented by the grid Laplacian. The projection of the heterogeneous property field along these basis functions gives the basis coefficients that form the reduced order representation. Subsequently, for each training datapoint, streamlines are traced and the minimum time of flight (TOF) representing the tracer breakthrough time at each producer is recorded. The basis coefficients and well rates are fed to a machine learning model as input and the minimum TOF at the producers forms the output of the model. This trained model can then be used along with an optimizer for computing the optimal injection rates to maximize the injection sweep efficiency. This corresponds to minimizing the variance in the minimum TOF within each well group. Different architectures of neural network are tested using 5-fold cross validation to decide the best ML model to compute the streamline time of flight. The trained model is used to perform well rate optimization over multiple realizations of geology by using a risk tolerance penalty. The optimal well rates thus obtained are compared with two cases: a) equal well rates assigned to all injectors and producers and b) well rates obtained by optimizing over a single realization without considering the uncertainty in geology. The optimal well rates are seen to offer better oil recovery and sweep efficiency than both cases.

The workflow is tested for a 50x50 two-dimensional (2D) heterogenous permeability field and for the SPE benchmark Brugge field, and is seen to result in significant improvement in oil recovery and sweep efficiency. A single forward run of the trained ML model is faster than the conventional simulator by about 3 orders of magnitude, making the approach suitable for large scale field application accounting for geologic uncertainty. The parsimonious representation of geologic heterogeneity and the use of ML for forward modeling makes the approach highly scalable and well-suited for full field applications.
Interfacial Viscoelasticity in Crude Oil-Water Systems to Understand Incremental Oil Recovery
Authors: Saad Ahmed M. , Aime Stefano , Mahavadi Sharath C. , Song Yi-Qiao , Patzek Tadeusz W. , Weitz David
Published: October 2020

Improved oil recovery from asphaltenic oil reservoirs may provide the world with a significant source of lower-cost energy over many decades. However, the mechanisms through which the surface-active components in crude oil, such as asphaltenes and organic acids, affect incremental oil production are still unclear.

In this study, we investigate crude oil/water interfacial films using shear and dilational rheology for mechanical properties and Fourier-Transform Infrared Spectroscopy (FTIR) to better understand its molecular species present at the interface that contribute to the development of viscoelastic behaviors. Dilational rheology has proven to be more sensitive to early time development of elasticity. In contrast, shear rheology provided more insights regarding the formation of elastic films at the macroscopic scale and late time interfacial changes. The presence of salts such as sodium chloride in the aqueous phase played a critical role in altering the dynamics of both the rheological properties development and the interfacial tension.
An Integrated Approach to Optimize Drilling, Completion and Hydraulic Fracturing Performance in Unconventional Wells
Authors: Omer Mohammed , Fragachan Francisco E.
Published: October 2020

In the age of artificial intelligence, digitalization, rising energy demand, falling prices of barrel of oil and increasing difficulty in oil & gas recovery we need to have an integrated approach based on physics, artificial intelligence and rock mechanics to reduce the non-productive time in drilling and -in parallel- enhance well production. The integrated approach should help in reducing cost, minimize human intervention, reduce drilling associated risks, minimize the negative impact on near wellbore rock behavior due to stimulation and enhance the recovery of hydrocarbons.

Stuck pipe is a major stake holder in "non-productive time" and is estimated to cost the oil and gas industry around $250 to $300 Million a year. Stuck pipe due to wellbore stability issues is a regular phenomenon while drilling weak zones in minimum stress direction especially in Middle East. William Lyon's in 2010, estimated that cost of stuck pipe in deep oil and gas wells is around 25% of overall budget.

To counter stuck pipe, for instance, drilling engineer may decide to increase the mud weight inorder to minimize the wellbore stability issues, and this could enhance challenges to a stimulation engineer associated with potential damage. Simliarly, an improper acidizing could soften the rock and negatively impact mechanical response of near wellbore rock during production. Two simple examples demonstrate the value of an engineering holistic approach based on wellbore stability integration into hydraulic fracturing treatment design considering the complexity involved around geomechanics.

This study introduces a workflow that holistically integrates a rock mechanics approach to optimize drilling performance and characterize the stresses around the wellbore with the completion design, combining the geomechanical and petrophysical properties to optimize the completion and stimulation design. This engineering workflow will enable to design and customize a particulate diverter system for effective fluid diversion and wellbore coverage by uniformly distributing the stimulation fluid with an aim to create fracture network complexities, enhancing the production. Additionally, this paper showcases the learnings from various field case histories including but not limited to drilling across weak bedding plane from Asia, wellbore stability issues in Middle East that resulted in high non-productive time from drilling, Uniform Fracture Growth from Horizontal Wells and re-fracturing strategies from North and South America.

This approach will enable optimizing well performance from drilling to production, minimize risks and optimize intervention by retro alimenting each phase of the process to the next. This workflow provides a innovative strategic approach optimizing drilling, completion and stimulation mitigating challenges in unconventional formations that can be extrapolated to conventional reservoirs as well.
On Some Factors Affecting Casing Collapse Resistance under External Pressure
Authors: Lin Bisen , Coe David , Harris Richard , Thomas Timothy
Published: October 2020

Casing collapse under external pressure is a complex phenomenon and is one of the governing factors in the tubular design of oil and gas wells. Collapse strength of a casing depends on its outer diameter to wall thickness ratio (i.e. D/t), material Young's modulus, yield stress, shape of stress-strain curve, temperature, ovality, wall eccentricity, circumferential residual stress, as well as combined loadings. This paper studies the quantitative effects of two geometric impefections, namely (i) wear on the inside diameter (ID) of casing and (ii) wall eccentricity angle; as well as two combined loading scenarios: (iii) dogleg bending and (iv) axial compression. Although these scenarios are not covered in the industry Standards, such as API TR 5C3 (June 2018 edition) [1], they are important factors that must be considered in the tubular design of oil and gas wells.

In order to quantify the effects of the four scenarios listed above, nonlinear parametric collapse Finite Element Analysis (FEA) studies were performed. Modified Riks method was utilized to predict the casing on-site collapse pressure as well as the unstable post-collapse response. Both material and geometric nonlinearities were taken into account. Elastic-plastic material property with strain hardening was incorporated in the collapse FEA models.

Based on the results of the parametric FEA simulations, some important observations and conclusions can be made: (i) for the scenario of casing ID wear, reduction in worn casing collapse resistance is nearly proportional to the reduction in minimum worn thickness regardless of the casing dimensiosns and material grade; (ii) for the case of wall eccentricity irregularity, as the circumferential location of maximum wall thickness moves closer to the minimum wall thickness location, the casing collapse resistance decreases; (iii) casing collapse resistance decreases as the dogleg severity (DLS) increases. Moreover, the effect of dogleg bending on collapse resistance has a strong dependence on casing dimensions and material grade; (iv) in contrast to the effect of axial tension, dependence of collapse resistance on axial compression is quite nonlinear and non-monotonic. In other words, as axial compression increases, collapse resistance increases until the axial compression reaches approximately 50% to 60% (primarily depending on D/t ratio) of yield strength, and then decreases as axial compression increases further.
Carbonate Caprock-Brine-CO2 Interaction: Alteration of Hydromechanical Properties
Authors: Sang Guijie , Liu Shimin
Published: October 2020

Caprocks play a crucial role in geological storage of CO2 by preventing the escape of CO2 and thus trapping CO2 into underlying porous reservoirs. An evaluation of interaction-induced alteration of hydromechanical properties of caprocks are essential to better assess the leaking risk and injection-induced rock instability, and thus ensuring a long-term viability of geological CO2 storage. We study the changes in nanopores, elastic velocities and mechanical responses of a carbonate caprock due to rock-water/brine-CO2 interaction (CO2 pressure ~ 12 MPa; 50 ℃). Before the interaction, the total and accessible porosities are 1.6% and 0.6%, respectively, as characterized by the Small Angle Neutron Scattering (SANS) technique. SANS results show that the total porosity of the carbonate caprock increases apparently due to rock-brine-CO2 interaction and the increasing rate rises as brine concentration increases (2.2% for 0M NaCl, 2.6% for 1M NaCl, and 2.7% for 4M NaCl). The increase total porosity is due to the dissolution of calcite which tends to enlarge accessible pores (by 0.8%-1.2%) while slightly decrease the inaccessible pores (by 0.1%-0.2%). Under CO2-acidified water environment, P- and S-wave velocities (5536.7 m/s and 2699.7 m/s) of a core sample containing natural fractures decreases by 8.5% and 8.1% respectively, while both P- and S-wave velocities (6074.1 m/s and 3858.8 m/s) for a intact sample show only ~0.5% decreases. The interaction also causes more than 50% degradation of the uniaxial compressive strength for the core sample with natural fractures.

We also conduct simulations of the single-phase creeping flow and two-phase water-CO2 flow in micron-scale natural fractures, as extracted from X-ray Micro-CT images of the core sample. The simulated absolute permeability (2.0×10-12 m2) is much higher than the matrix permeability (6.7×10-20 m2before the interaction; 1.3×10-19 m2after the interaction), as calculated based on the Kozeny–Carman Equation. This indicates that natural fractures provide preferential flow paths for CO2 while flow through caprock matrix can be reasonably neglected. Simulation results also indicate that CO2 preferentially migrates in the natural fractures where there are more inter-connected and permeable channels. The study recommends that more attention should be addressed on interaction-induced alteration of fracture/faults permeability/stability, and its effect on the sealing integrity of carbonate caprocks.
Maximizing the Effectiveness of Global Virtual Teams
Authors: Holding Eagle L. M.
Published: October 2020

Global virtual teams (GVTs) are an ever-expanding reality in today's oilfield. In comparison to a traditional team in which individuals are co-located and regularly work face-to-face to accomplish their goals, GVTs work while separated by time, space and even culture. Their use allows organizations to leverage a concentrated group of technical experts in combination with local teams. However, GVTs operate differently than co-located teams. When organizations assume otherwise, they are likely to be disappointed with the results.

This paper consists of a review of scholarly literature along with news sources, observations and interviews with individuals who work in GVTs in the oilfield.

Maximizing the benefit of GVTs requires organizations to acknowledge and accommodate the manners in which global virtual teams differ from co-located teams. When this is not done, teams will lack efficiency, yield poorer performance, and result in a less satisfied workforce. While personal leadership styles such as transformational leadership are often found to be most effective for co-located teams, shared leadership as well as styles that are less relationship-based may be more effective when face-to-face interactions are less accessible. Much of the communication in global virtual teams is computer-mediated and asynchronous, for example, by email. Without body language, tone of voice, and real-time reactions, this kind of communication often invites misunderstandings and fails to convey team member intent. This can be especially challenging during inter-cultural communication. Technologies such as phone calls, web- and video-conferencing, and even augmented reality can enrich and improve the effectiveness of communication. Flexible scheduling can also help teams who are separated by multiple time-zones. Finally, team cohesion and effectiveness can be substantially improved through judicious use of travel for working site visits where teams have a chance to work together in real-time as well as engage in personal social interactions. Increasing the intentionality with which organizations support and manage their GVTs has the potential to substantially increase their effectiveness.

Despite the prevalence of GVTs in oilfield organizations, a search on this topic in the OnePetro oilfield literature database yields few results. This paper describes many of the challenges that exist within global virtual teams that are less likely to be present within co-located teams. It also proposes leadership strategies, technology, and other methods that organizations can use to overcome these challenges and maximize the effectiveness of their GVTs.
Lessons Learned From In-Bit Weight and Torque Measurement
Authors: Vempati Chaitanya , Moss William , Townsend Todd , Schandorf Cecil , Evans Kenneth
Published: October 2020

During the last decade, a tremendous amount of work has been published on using surface measurement of mechanical specific energy (MSE) for enhancing drilling efficiency and maximizing rate of penetration (ROP). With an increase in directional drilling, surface measurement of MSE doesn't correlate with downhole conditions due to frictional losses along the drill string and bottom hole assembly (BHA). Attempts to measure weight on bit (WOB) and torque on bit (TOB) downhole typically involve expensive tools that are deployed 50-100 feet behind the bit. The authors present a novel in-bit strain sensor that measures WOB and TOB in the bit while drilling. This new approach is completely non-invasive and does not change the BHA. Field testing has shown that in many circumstances only 50% of the surface indicated weight reaches the bit and drilling performance suffers including low ROP and higher vibration levels. This highlights the importance of managing the directional plan and using methods to improve weight transfer. This new in-bit measurement tool has been used to drill over 100,000ft in applications around the world and provides useful insights into drilling performance.
On-the-Fly Proppant Flowback Control Additive
Authors: Zha Charles , Green John , Abrams Benjamin , Cabori Logan , Hamori Kevin , Harper Adam
Published: October 2020

This paper covers the research, development, and field application of a cost-effective, on-the-fly chemical additive that reduces proppant flowback during well production. Laboratory tests and field results, showing the effect this chemical additive has on proppant flowback, are examined.

Previous proppant flowback prevention methods are reviewed. Laboratory tests that were performed to ensure effective on-the-fly coating in the blender tub, as well as the ability to control proppant flowback, are also analyzed. A review of fracturing treatments performed in wells utilizing the proppant flowback control additive (PFCA) is provided. Post-fracture treatment proppant flowback and production results are compared to direct offset wells using conventional proppants. Fracturing treatment designs, formation characteristics, and proppant types are presented.

Laboratory proppant flow tests show PFCA-treated proppant can withstand a much higher critical flow rate than uncoated fracturing sand. Unconfined compressive strength tests indicate that proppant is coated efficiently in the blender tub, enabling effective consolidation at downhole conditions. The results of laboratory tests are used to explain and support the field case studies. The field case studies show that use of PFCA significantly reduces proppant flowback and typically results in higher hydrocarbon production when compared to conventional proppants used in offset wells.

With completion designs moving to finer mesh size proppant and higher proppant loadings per lateral foot, operators are increasing spending to deal with higher amounts of proppant flowback. This paper introduces an important technology that is an economically viable and beneficial substitute for traditional proppant flowback prevention methods.
A Machine Learning Approach to Reduce the Number of Simulations for Long-Term Well Control Optimization
Authors: Santos Daniel Rodrigues , Fioravanti André Ricardo , Santos Antonio Alberto , Schiozer Denis José
Published: October 2020

A long-term well control strategy is frequently selected using optimization methods applied to reservoir simulations. However, this approach usually requires a large number of simulations that can be computationally demanding. In this paper, we evaluated several machine learning (ML) techniques to reduce the number of simulations for optimizing long-term well control strategy while preserving the quality of the solution.

We proposed a methodology, denoted as IDLHC–ML, which combines many ML techniques with iterative discrete Latin hypercube (IDLHC) – a gradient-free optimization algorithm that was successfully applied in previous work – to optimize the coefficients of the logistic equation that guides the well's bottom-hole pressure along the time horizon. In IDLHC-ML, we used a set of simulation runs from the first iteration to train the initial ML models. From the second iteration onwards, we employed the trained ML models to predict the net present value (NPV) and only a percentage of the scenarios, which were expected to have the best NPV, were then simulated. As we simulated new scenarios, we updated our ML models to further improve predictions. For a fair comparison, we set the same values for the optimization parameters of IDLHC to the IDLHC–ML and, then, we compared the NPV and the number of simulation runs considering different configurations of IDLHC parameters. In this paper, we evaluated a total of twelve ML regression techniques, such as Bayesian Ridge, Random Forest, and stacked ensemble learning, which consists in using the predictions from multiple ML algorithms as input to a second-level learning model.

To minimize random effects, we repeatedly applied IDLHC and IDLHC–ML five times in a single reservoir model (nominal optimization). The results showed that, depending on the IDLHC optimization parameters, IDLHC-ML reduced at least 27% of simulations while keeping the equivalent NPV statistical metrics calculated in all five repetitions, when compared to IDLHC. Moreover, the best ML technique for IDLHC–ML varied with the IDLHC set of optimization parameters. To conclude, the method proposed here was able to reduce a significant amount of computational time by curtailing the total number of full-physics expensive reservoir simulations, with the help of fast and low-cost ML models.

There are many published studies in well control optimization, but these generally involve high computational demand. In this sense, ML methods revealed to be an adequate and inexpensive alternative in reducing the number of simulation runs in well control optimization. The methodology is generic and it can be applied under uncertainties, and for more complex cases.
A Paradigm Shift in Drilling Frac Plugs in Extended Laterals – A Permian Basin Case History
Authors: Krane Benjamin , DeFriend Matthew , Garza Heberto , Frantz Joseph , Tourigny Matt , Griffith Jared
Published: October 2020

Wells in the Permian Basin continue to increase in technical complexity and lateral length, testing the limits of traditional completion practices in unconventional wells. Coiled tubing has been the standard method for drilling out frac plugs in the basin but has mechanical limitations in extended-reach and high-pressure laterals. Due to the increasing well complexity operators have begun using high technology hydraulic completion units (HCU), also known as a snubbing unit, to drill out frac plugs in certain Permian Basin wells. By using the HCU in wells with longer laterals, higher pressures, and downhole uncertainty/complexity some of the additional risk can be mitigated. The HCU system can provide a reliable and cost-effective means to cleanout laterals in the Permian Basin while reducing mechanical risk. The purpose of this paper is to present case histories that illustrate the positive impact of the HCU on field operations. This paper will also detail the evolution of the HCU over time to its current state of the art stand-alone rigless system.
Transient Volume of Investigation: Definition, Theory, and Applications
Authors: Spivey J. P. , Lee W. J. , Sheikh Hafiz Mustafa
Published: October 2020

The transient volume of investigation extends the concepts of radius and depth of investigation (for radial and linear flow, respectively). However, it is far more general, with much broader applicability. Unlike the specific cases of radius and depth of investigation, the volume of investigation is independent of flow regime, geometry, and model. Thus, the transient volume of investigation is applicable even when no recognizable flow regime is present.

The transient volume of investigation is based on fundamental properties common to all constant-terminal-rate solutions to the diffusivity equation. It is defined as the minimum reservoir volume necessary to provide sufficient pressure support to produce the observed rate of change of sand-face pressure as a function of time.

The volume of investigation is a paradigm-changing concept. It is the only meaningful reservoir characteristic that is both easily estimated and model independent. It provides a rigorous lower bound on fluid in place investigated as a function of time during a test, independent of flow regime, geometry, model, and even permeability heterogeneity or anisotropy.
Reservoir Pressure Monitoring for Waterflooding Optimization using Downhole Dummy Pressure Sensors Installed in Injection Wells with Selective Strings
Authors: Tellez Camilo , Gonzalez Belo Patricio , Florez Fabian , Taborda Tatiana , Villa Carlos , Bonfanti Benjamin , Acosta Tito , Zuluaga Wendy , Parra Marly
Published: October 2020

Casabe is a multilayer field (20 reservoirs distributed in 3 formations) characterized high heterogeneous nature, limited sand continuity, unfavorable mobility, and high sediment production due to a poor consolidation of the reservoir. The ongoing waterflooding process has a well defined five-spot pattern where injection wells have selective strings installed, and production is commingled. Under these conditions, shut-in wells for reservoir pressure acquisition are challenging activities with high operational risks related to compromised mechanical integrity and sediment production. Likewise, the commingled production scheme affects the deconvolute pressure data process and promotes crossflow effects leading to inconsistent results. Finally, stoping the well involves production loss and disruption in waterflooding balance. The reservoir pressure is a critical requirement to run an analytic optimization methodology implemented in 2017. Casabe had proven that selective injection string offers a unique opportunity to acquire quality reservoir pressure data by reservoir unit using the Downhole Dummy Pressure Sensors (DDPS), overcoming all the above issues when acquired in producers.

This paper presents how a waterflooding optimization methodology coupled with a quality reservoir pressure acquisition enhanced reservoir surveillance by triggering actions to optimize the waterflooding volumetric balance, thus, reaching a production-injection system stabilization. This enhancement changed the area production decline trend and allowed to contact more zones and produce oil from constrained layers.
Deep Learning Based Hydraulic-mechanical Simulation of Petroleum Reservoirs
Authors: Wang Shihao , Liang Luming , Zhang Yanbin , Wen Xian-Huan , Wu Yu-Shu
Published: October 2020

Knowing that accurate yet time-efficient multihpysical reservoir simulation is a major challenge, we have developed a deep neural network (DNN) based multiphysical simulator to acceletate the geomechanical calculation. We first generated 20,000 pressure -stress pairs by conducting regious multiphysical simulation with various mechanical properties using a full physics reservoir simulator. All data pairs are simulated by 128 *128 grid blocks.

We then developed a U-Net network, a proven structure in image segmentation based on convolutional neural network (CNN), and trained the network with the generated data using Tensorflow. The U-Net network takes the pressure field as the input and regresses the stress field in a pixel-to-pixel manner. The model is trained with 100 epochs using Adam optimizer with a learning rate of 0.001 on GPU. The trained network is thereafter deployed in the reservoir simulator to predict the stress field from numerically solved pressure field at time step level. Hence the geomechanical simulation is replaced by the DNN proxy.

Our results show that the accuracy of the U-Net network is above 97%, in the metric of mean square error. Moreover, the U-Net network possesses excellent capability for dimension generalization. With the implementation of the proxy DNN simulator, the simulation time spent in the geomechanical module has been reduced by more than 95% on a 256*256 case study.

The novelty of our work lies in the pioneering application of DNN method to train and predict the time-dependent stress field, avoiding the curse of dimensionality. Our trained model can be conveniently connected with an existing reservoir simulator, which greatly saves the efforts of code development.
Water-Oil-Gas Settling Interface Calculation in Shut-In for Undulating Well
Authors: Kang Yongfeng , Gonzales Adolfo , Samuel Robello , Liu Zhengchun
Published: October 2020

Modern directional wellbore trajectories are more complex now with some wells having an undulating trajectory. When installing artificial lift devices such as an electric submersible pump (ESP), the pump must be submerged in the liquid phase of the hydrocarbon in order to avoid gas-lock issues, including in shut-in conditions. Incorrect placement of such device would require a very costly remedy. In an undulating trajectory well, it is possible that the fluid in the well is in the gas phase at some of the downhole upper elbow locations during shut-in. This paper presents a method to calculate the water/oil/gas settling interface during shut-in conditions for an undulating trajectory well.

In this method, the well is divided into multiple uphill and downhill sections. For each section, it is assumed that the GOR (Gas Oil Ratio) and WOR (Water Oil Ratio) are the same as the production GOR and WOR. The pressure at the elbow turning point of two uphill and downhill sections is assumed to be the same to ensure the pressure continuity. Then, by the given surface or bottom (reservoir) pressure, the gas/oil and oil/water interfaces are calculated with iterations with a numerical method to match the GOR and WOR considering the wellbore pressure and temperature effect for each section. Once all the sections are calculated, the final results are combined to achieve the global gas/oil and oil/water interfaces and the pressure and temperature profiles.

This method has been implemented in an advanced casing and tubing design application to calculate the well pressure and temperature profiles, and then these profile results are applied later for further stress analysis. A typical undulating well is presented for case study to explain the calculation steps and results. As expected, the gas/oil and oil/water interfaces are obtained where the water is settling at the lower elbow of the well, the gas phase is accumulated at the upper elbow of the well, and the oil phase stays in the middle between the gas and water. The pressure profile is achieved showing different pressure gradients of the gas/oil/water settling intervals and pressure is continuous along the whole well. The temperature profile is also obtained, showing different temperature behavior for gas, oil, and water intervals with different shut-in duration, which is useful for stress analysis in the string at different depths.

This paper fills a gap that has not yet been discussed in the industry literature. It is an important for field application, especially for choosing the artificial lift device installation depth. Further, the calculated pressure and temperature profiles are useful for casing and tubing design stress analysis purposes.
Improving Casing Running Operation Success in Long Laterals by Using Bottom Hole Assembly Tripping Load Analysis
Authors: Baker Alexa , Khochbar Namig , Leonard Benjamin , Tan Hui Xian
Published: October 2020

As horizontal wells have come to dominate shale and tight development programs, US land rigs have experienced challenges with running production casing on elevators to total depth (TD) in long laterals (≥10,000 ft). An initial study was done, and the results identified a relationship between the level of open hole drag when tripping out with the final lateral bottom hole assembly (BHA) and the success rate of casing running operations. The study results led to further investigation to determine if there was a correlation that could be applied more broadly to improve overall performance. Front end engineering work included analyzing offset data to establish the baseline of successful casing running operations and building engineering models to evaluate the level of open hole drag. The level of open hole drag was determined by modeling the hookload profile when tripping out with various friction factors, characterizing the hookload signatures, and building a correlation with real-time hookload data. A workflow was then developed with a focus on monitoring the first five to ten stands tripped out of the hole to determine if additional hole cleaning was necessary based on the observed real-time friction factor. This methodology and workflow have been used successfully to support numerous operations in the Permian and Marcellus Basins. As a result, the success rate of running casing on elevators to bottom in these two areas have improved significantly, the results for the Permian Basin can be seen in Fig. 1.
Difference-Value Plotting Function for Pressure Transient Analysis in Low-Permeability Reservoirs
Authors: Luo Le , Lee John , Blasingame Thomas
Published: October 2020

This paper proposes the difference-value plotting function (DVPF) for the diagnostic analysis and interpretation of pressure transient test data in low-permeability reservoirs. Specifically, this work uses the approximation of the analytical solution for the performance of a vertical well with a single finite conductivity vertical fracture, where a Taylor Series expansion is used to obtain an asymptotic solution for early-time flow, which includes terms for wellbore storage and fracture conductivity. The well-testing derivative of this result is then obtained and is of a similar form.

By subtracting the derivative form from the pressure form, we remove the "dominant" wellbore storage term from the asymptotic solution. We then need to normalize that difference by the square root of time (or dimensionless time) to obtain the final formulation of the DVPF which leaves a single constant parameter multiplied by time on the right-hand-side. Our contention is that this formulation leaves us with a diagnostic plotting function which provides a unique and contrasting behavior compared to using the pressure drop and/or pressure drop derivative functions alone for diagnostics and interpretations.

As is typical of pressure transient or well testing data at early times, the observed pressures often exhibit random data noise. As such, we have adapted a noise reduction algorithm that was originally used for signal processing to smooth both the pressure and derivative functions.

Lastly, we demonstrate the difference-value plotting function (DVPF) on several cases of synthetic and field-derived data to illustrate the utility of this methodology. Specifically, we have applied this method to cases in which it is difficult to determine unique interpretations using traditional methods (e.g., insufficient duration tests, lengthy WBS distortion, and effects of ultra-low permeability). The proposed DVPF allows us to observe underlying characteristics that are obscured at early times in traditional pressure and derivative analysis, and for the demonstration examples provided in this work, the DVPF does provide a strong auxiliary means of interpretation.
The Impact of Practical Experiences on the Development of Petroleum Engineering Education
Authors: Retnanto Albertus , Alyafei Nayef , Fadlelmula Mohamed , Sheharyar Ali
Published: October 2020

The practical application of petroleum principles is the key to optimum petroleum engineering education. Although some of these skills are required and often emphasized by accreditation bodies, mastering them requires vision, planning, and allocation of time and budget by academic institutions. Enhancing the efficiency and effectiveness of teaching and active learning of practical relevance can be achieved through applying information technologies and performing undergraduate research experience program. Research experiences support students in comprehending a phenomenon in an area that contains practical experiences, specifically in petroleum engineering. In Qatar, a national funding initiative called the undergraduate research experience program (UREP) is available, and luckily almost all the petroleum engineering students at Texas A&M University at Qatar (TAMUQ) participate in UREP. Research provides an iterative process to develop how knowledge evolves. Not only that, but several field trips are arranged annually for the students to visit onshore rigs and facilities in the state of Qatar. Adding to that, in-house virtual reality (VR) offshore rig and geological site were developed that can waive several difficulties in arranging an actual visit. The information technologies bridge formal and informal learning by connecting the students to real-world experiences. In this paper, surveys were conducted among former students on the value of independent student research on developing their skills. Also, the value of actual and virtual field trips on enhancing their understanding of petroleum engineering concepts were measured through the conducted surveys. The results of surveys indicate that the provided experiences significantly enhanced both the skills and learning experiences in the petroleum engineering education of former students in their workplace. Feedback came from the students that research experiences developed the students' skills that complemented their workplace skills. Also, recommendations were made to embed the VR field trip in more petroleum engineering courses. Moreover, concepts in courses such as Drilling and Production Engineering, as well as Geology of Petroleum, became easier to grasp after these trips.