bluuebunny/crossref_metadata_2025 huggingface dataset:
Rigsite Thermal Treatment of Cuttings Enables Improved HSE Performance in 24-Well Campaign in the UK North Sea
Authors: Smith John , Eccles Graham
Published: September 2019

On offshore rigs, oil-based mud (OBM) cuttings can create logistical and environmental risks. Onshore disposal requires costly transport, and bad weather can halt shipping operations. The liability for waste treated onshore belongs to the operator. Although offshore disposal removes this liability, UK North Sea regulations specify that oil on cuttings (OOC) must be less than 1%. (by weight?) A rigsite thermomechanical cuttings cleaner (TCC) applies high temperatures to help reduce OOC to less than 1% and recovers base oil and water for reuse.

A TCC unit was installed on a semisubmersible rig to process OBM cuttings for a 24-well program. Mechanical action is applied directly to the cuttings by means of hammers that create friction, causing temperatures to exceed the boiling points of water and oil so that hydrocarbons are separated. The oil and water vapors are removed and condensed where the base oil and water are further separated and recovered. The TCC process on this rig was supported by vacuum-pump conveyance equipment and specialized storage tanks. Cuttings were no longer shipped to shore, and crane lifts associated with "skip-and-ship" operations were minimized significantly.

The TCC unit processed 14,500 metric tons (MT) of OBM cuttings throughout the duration of the 24- well program. The total footage drilled with OBM was more than 160,000 ft. All cuttings were disposed offshore. Approximately 13,500 bbl of base oil (valued at USD 135/bbl) was recovered for reuse in the drilling fluid system. The TCC unit ran for a total of 3,500 hours with zero downtime or nonproductive time (NPT) associated with cuttings disposal. The average is approximately 150 operating hours per well. One important benefit was the dramatic reduction of skips handling and crane lifts, which provided safer working conditions for rig crews. On a conventional skip-and-ship operation, the operator would fill and transport up to 35 skips per day. This translates to 2,380 crane lifts per well that were unnecessary. Offloading delays caused by bad weather were no longer a factor, thus helping reduce uncertainty and saving valuable rig time. Processing this volume of drill cuttings offshore meant that more than 57,000 skip crane lifts were avoided. The TCC mobilization process for this program was executed efficiently by coordinating with quayside contractors (welders, platers, electricians, etc.) to complete much of the installation work scope onshore.

Thermal treatment enables operators to address stringent offshore discharge regulations globally, excluding countries with zero discharge policies. Cost benefits include the following: No "wait on weather" time (rig day rate = USD 300,000)No dedicated vessels for transportNo quayside cuttings handlingNo trucking to treatment and disposal facilities

Safety and environmental benefits add the following value: Reduced manual handling of skipsReduced crane liftsBase oil reuseLiability for waste ends at rigsite
Multicomponent Diffusion Modeling of Cyclic Solvent Injection in Ultratight Reservoirs
Authors: Cronin Michael , Emami-Meybodi Hamid , Johns Russell
Published: September 2019

We present a new semi-analytical compositional model specifically designed for hydrocarbon recovery (primary and cyclic solvent injection processes) in ultratight oil reservoirs based on multicomponent diffusion-dominated transport within the matrix. The semi-analytical solution consists of a well-mixed tank model for the fractures coupled to diffusive transport within the matrix. Production of oil, gas, and water from the fractures is proportional to its phase mobility. The matrix allows for differing effective diffusion coefficients for each component. Because there are no grid blocks within the matrix the analytical solution is computationally less expensive than numerical simulation while capturing the steep, non-monotonic compositional changes occurring a short distance into the matrix owing to multiple injection cycles. The Peng-Robinson equation-of-state is used to calculate phase behavior within the analytical framework.

The solution is validated with several lab and field-scale cases. For primary recovery, the results show that the diffusion-based model correctly reproduces the pressure and oil recovery declines observed in the field. We show that the hydrocarbon recovery mechanism for solvent huff’n’puff (HnP) is facilitated by greater density reduction and compositional changes (increased compositional gradients). Two solvents are considered in HnP calculations; carbon dioxide (CO2) and methane (CH4). Recovery of heavier components is enhanced with CO2 compared to CH4, but methane has overall greater oil recovery than carbon dioxide for the cases considered. Furthermore, the results demonstrate that multiple HnP cycles constrained to surface injection are needed to enhance density and compositional gradients, and therefore oil recovery. While shorter soaks are better for short-term recovery (i.e. 3 to 5 years), longer soak periods maximize recovery over a longer timeframe (i.e. 10 to 15 years). This paper provides a novel way to model the optimum number of cycles and duration and when to start the HnP process after primary recovery for the limiting case of diffusion only transport where matrix permeabilities are very small (k < 200 nD).
Time-Enhanced Material Balance Analysis
Authors: McNeil Ralph G , Antonov Aleksandr , Tabatabaie S. Hamed , Mattar Louis
Published: September 2019

The traditional Material Balance Analysis only utilizes cumulative production and static average reservoir pressure. Time does not feature in the equations. However, there are significant advantages if time is incorporated into the analysis. For example: a) identifying if all the wells belong to the same reservoir; b) identifying the effect of external energy sources such as gas or water drive; c) incorporating the contribution of communicating tight reservoirs; d) visualization of the results in pressure-time format.

The time-based analysis presented in this paper supplements the conventional methods. It helps reduce the non-uniqueness of the solution. In contrast to the conventional Havlena-Odeh plotting variables, which are complex and non-intuitive, the pressure-time plot and corresponding pressure-history match are much easier for an engineer to comprehend and to evaluate the validity or uniqueness of the results.
Optimization of Multi-Fractured Horizontal Well Completion: A Montney Example
Authors: Haghshenas Behjat , Qanbari Farhad
Published: September 2019

After a successful decade of exploration and development activities in major tight/shale reservoirs, the industy now has access to incredible sets of data, modeling tools, and technologies for multi-fractured horizontal well (MFHW) completion. A review of the available data and models shows that performance of a MFHW is governed by hydraulic facture properties (dimension, conductivity, and distribution) and reservoir fluid and rock characteristics (reservoir fluid properties, and rock storage and flow capacities). Workflows are required to link the characterization attempts (reservoir and MFHW), learnings from completion expriments, modeling approaches (reservoir and fracture modeing) and pettern recognition exercises (relationship between well performance metrics and the governing parameters).

In the current study, an interative workflow is proposed for design and optimization of MFHW completion based on a mixed-method approach combining three major paradigms: experiments, modeling, and data science. Each cycle of the workflow starts with data gathering and characterization of reservoir fluid and rock, followed by reservoir and fracture modeling, statistical analysis, updated design, economc analysis, and ends with implementation, monitoting and data analysis. The first cycle of the workflow is the most time-consuming and tedious one which requires a great deal of discussions and instructions.

The proposed workflow is tried on a population of Montney gas condensate wells. Rate-transient analysis (RTA) and numerical reservoir modeling were applied to a group of 16 Monteny gas condensate wells with detailed daily production and flowing pressure data. Further, a simplified RTA-based approach and statistical analysis were applied to more than 90 Montney gas condensate wells (from the same region) with publically available production data.

A new design with optimized completion paramteres is obtained from the results of RTA, numerical reservoir modeling, statistical and ecnomic analyses. The new design is applied to six new wells in the same area. The average performance of the new wells is reasonably close to the predicted performance by the proposed workflow. The workflow is believed to optimize the well performance, save the operator millions of dollars through optimization, and give the management and technical teams confidence in the next phase of corporate planning.
Comparison of the Methods for Analyzing Rate and Pressure Transient Data from Multistage Hydraulically Fractured Unconventional Gas Reservoirs
Authors: Atadeger Aykut , Batur Ela , Onur Mustafa , Thompson Leslie G.
Published: September 2019

In this study, we provide a detailed review and comparison of the various graphical methods, available in the literature, to interpret/analyze rate and pressure transient data acquired from multistage hydraulically fractured horizontal wells (MHFHWs) completed in unconventional gas reservoirs. The methods reviewed are based on transient matrix linear flow (Ibrahim and Wattenbarger 2006; Nobakht and Clarkson 2012a, 2012b; Chen and Raghavan 2013) and boundary-dominated flow due to the stimulated reservoir volume (SRV). The methods for boundary-dominated flow are the contacted volume methods based on the ending times of linear flow (Wattenbarger et al. 1998; Behmanesh et al. 2015) and the material balance methods (FBMs); Agarwal-Gardner method (Agarwal et al. 1999) and conventional method involving plotting rate-normalized pseudo pressure versus pseudo time material-balance time. We delineate the advantages and limitations associated with each method and identify the best methods of interpretation and analysis. Three different production modes; constant rate (CR), constant bottomhole-pressure (CBHP), and variable-rate/bottomhole pressure, are considered. For comparison, various synthetic test data sets generated from a high-resolution spectral gas simulator, which treats nonlinear gas flow rigorously and accurately to simulate rate transient data, is used. Both synthetic noise-free and noisy rate/pressure data sets considering wide ranges of initial reservoir pressure and bottomhole pressure as well as real field data sets are used to compare the methods. For linear flow, the Nobakht-Clarkson method yields the best results, although its use is tedious as it requires an iterative procedure. The Chen-Raghavan method for linear flow seems to provide comparable results to the Nobakht-Clarkson method, but does not require iterative procedure. The Ibrahim-Wattenbarger method for linear flow analysis always overestimates flow capacity as compared to the other methods. For boundary dominated flow, the results show that the Agarwal-Gardner FBM method is quite vulnerable to the error in rate/pressure data, while the conventional FBM method is more robust to noise and provides more accurate estimates of gas in place. Among the methods based on the ending time of linear flow, it was found that unit-impulse method based on Behmanesh et al. (2015) provides best results for predicting gas in place.
A Robot for Removing Hydrate and Paraffin Plugs in Offshore Flexible Lines – Development and Experimental Trials
Authors: Santos Hugo , Perondi Eduardo , Wentz André , Silva Anselmo , Barone Dante , Basso Eduardo , Reis Ney , Galassi Maurício , Pinto Hardy , Castro Bruno , Ferreira André , Ferreira Lincoln , Krettli Igor
Published: September 2019

Methane Hydrates and Paraffin Plugs in flexible lines are concerns in offshore production. They may stop wells for months, causing high financial losses. Sometimes, operators use depressurization techniques for hydrate removal. Other strategy is using coiled tubing or a similar unit in order to perform local heating or solvent injection. However, frequently these strategies are not successful. In those cases, a rig may perform the operation or the line may be lost.

This project developed a robotic system in order to perform a controlled local heating and remove obstructions. The robotic system developed is able to access the line from the production platform. It uses a self-locking system in order to exert high traction forces. An umbilical with neutral buoyancy and low friction coefficient allows significant drag reduction. It allows moving upwards and in pipes with a large number of curves. Coiled tubing and similar units cannot do that. Carbon fiber vessels and compact circuits give flexibility to move inside 4-inch flexible pipes. A novel theoretical model allows the cable traction calculation using an evolution of the Euler-Eytelwein equation.

Experimental tests validated this model using curved pipes, both empty and filled with a fluid and using different loads. Experimental tests also validated the external layer traction resistance. Furthermore, the carbon fiber vessels were pressure tested, indicating a collapse resistance of more than 550 bar (8.000 psi). In addition, exhaustive tests of the onboard electronics and of the surface control system guarantee the communication reliability.

Additionally, the 25 kN (5.6 kip) traction system was modeled theoretically considering the self-locking system, the contact with the wall and a diameter range. Four prototypes allowed to: a) compare hydraulic and electric drive systems, b) validate the self-locking mechanism up to its limit, c) analyze the hydraulic system for leg opening and translation and d) prove the traction capacity. Finally, a theoretical model for the local heating system was developed. The system experimental validation on a cooled environment demonstrated its capacity of increasing temperature. Furthermore, it allows the obstruction removal in a controlled manner, avoiding damage to the polymeric layer of the flexible line.
Application of Inter-Fracture Injection and Production in a Cluster Well to Enhance Oil Recovery
Authors: He Youwei , Cheng Shiqing , Chai Zhi , Patil Shirish , Rui Ray , Yu Haiyang
Published: September 2019

Applications of cluster wells and hydraulic fracturing enable commercial productivity from unconventional reservoirs. However, well productivity decrease rapidly for this type of reservoirs, and in many cases, it is difficult to maintain a productivity that is economical. Enhanced oil recovery (EOR) is therefore needed to improve well performance. Traditional fluid injection from other wells are not feasible due to the ultra-low permeability, and fluid Huff-n-Puff also fails to meet the expected recovery. This work investigates the feasibility of the inter-fracture injection and production (IFIP) approach to increase oil production of multiple multi-fractured horizontal wells (MFHW).

Three MFHWs are considered in a cluster well. Each MFHW includes injection fractures (IFs) and recovery fractures (RFs). The fractures with even and odd indexes are assigned to be IFs or RFs, respectively. The injection/production schedule falls into two categories: synchronous inter-fracture injection and production (s-IFIP) and asynchronous inter-fracture injection and production (a-IFIP). To analyze the well performance of multiple MFHWs using the IFIP method, this work performs numerical simulation based on the compartmental embedded discrete fracture model (cEDFM) and compares the production performance of three MFHWs using four different producing methods (i.e., primary depletion, CO2 Huff-n-Puff, s-IFIP, and a-IFIP). Although the number of producing fractures is reduced by about 50% for s-IFIP and a-IFIP, they achieve much higher oil rates than primary depletion and CO2 Huff-n-Puff. Sensitivity analysis is performed to investigate the impact of parameters on the IFIP. The fracture spacing between IFs and RFs, CO2 injection rates, and connectivity of fracture networks affect the oil production significantly, followed by length of RFs, well spacing among MFHWs and length of IFs. The suggested well completion scheme is presented for the a-IFIP and s-IFIP methods. This work demonstrates the ability of the IFIP method in enhancing oil production of multiple MFHWs in unconventional reservoirs.
Numerical Investigation to Understand the Mechanisms of CO2 EOR in Unconventional Liquid Reservoirs
Authors: Zhang Fan , Adel Imad A. , Saputra I. W. , Chen Weidong , Schechter David S.
Published: September 2019

Observations from pilot wells along with laboratory experiments have revealed the significant potential of CO2 as an EOR agent in unconventional liquid reservoirs (ULR). This study focuses on unveiling the mechanisms of gas injection EOR through a combination of experimental results, ternary diagram analysis, and core-scale simulation. In addition, laboratory results were upscaled to the field-scale to evaluate the effectiveness of the CO2 injection in production enhancement from ULR.

Gas injection experiments were performed at different pressures, and the laboratory results were upscaled to evaluate the production enhancement through gas injection EOR in ULR. A CT-generated core-scale model was utilized to investigate the mechanisms of gas injection EOR. Mechanisms such as diffusion and multi-contact miscibility were determined from core-scale simulation through history-matching experimental results, then upscaled to the field-scale model. Ternary diagrams reveal that EOR by gas injection is only effective at pressures greater than the Minimum Miscibility Pressure (MMP). Alteration of the injected gas and composition of crude oil clearly has an implication on changing the ternary diagram.

The primary production mechanisms of CO2 EOR are multi-contact miscibility, vaporizing/condensing gas drive, oil swelling, and diffusion. Gas injection experiments recovered up to 45% of the Original Oil In Place (OOIP) at 3,500 psi, but the recovery factor was less than 5% when operating below the MMP. Diffusion has a minor effect in enhancing oil recovery in ULR based on the core-scale history-matching results. The multi-contact miscibility is found to be the primary driving mechanism for oil extraction during gas injection. Ternary diagrams analysis clearly demonstrates that MMP plays a significant role in gas injection and that miscible conditions need to be achieved for EOR projects in ULR. CT-scan technology is utilized to demonstrate the movement of the fluids inside the cores throughout the experiments. Thus, we can determine the high flow path regions of the core plugs. Additionally, the impact of injection pressure and the start time of the gas injection process were analyzed using the field-scale model. The simulation results indicate that gas injection has significant potential of enhancing oil production in ULR. This study not only reveals the mechanisms of gas injection in ULR, but also provides a method for designing and optimizing gas injection for Huff-n-Puff EOR.

This study challenges the paradigm that diffusion is the dominating parameter of CO2 injection EOR in ULR. The novelty comes from the establishment of gas injection EOR mechanism in ULR through a thorough analysis of laboratory experiments, core-scale simulation, and ternary diagram analysis. In addition, a new modeling workflow for the design of gas injection strategies is proposed to unveil the real potential of gas injection.
Case Study: Human Factors Analysis of FPSO Operations Activities in Brazil
Authors: Franca Josue , Luquetti dos Santos Isaac , Haddad Assed
Published: September 2019

Production and drilling activities in offshore installation are one of the most necessary activities of human society. To drill a subsea well and raise the crude oil to a platform, by itself, presents a series of risks. Associated with this activity, when the crude oil reaches the topside of the platform, there are a number of operations that prepare the oil and gas to be exported to land by pipelines or oil tanker vessels, which involves equipment and process that take high temperatures, high pressure and high flow rates. Understanding the dynamics of the factors that can affect the interaction of operators with all these offshore complex systems is critical, because the loss of control of these systems can cause serious accidents, resulting in injuries to workers, environmental damage, loss of production and geopolitical crises. Accidents in the oil and gas offshore installations, such as drilling rigs and FPSOs, can have tragic consequences and all efforts should be targeted to prevent its recurrence. Therefore, from the perspective of current technological developments, it is essential to consider the influence of Human Factors in the risk management of offshore industrial plants.
Career Development Essentials for Young E&P Technical Professionals
Authors: Lau Hon Chung
Published: September 2019

This paper discusses career development essentials for young E&P technical professionals to realize and use for career planning. By dividing the professional life of the E&P professional into the early-career, mid-career and late-career stages, each spanning about twelve years, the author discusses career development essentials and their benefits in each stage. In the early-career stage, essentials include understanding the corporate culture, developing technical depth and breadth and developing good interpersonal team skills. In the mid-career stage, essentials include developing leadership skills, moving out of one's comfort zone, mastering cross discipline competency and developing a strong professional network. In the late-career stage, essential include anticipating future trends, leveraging one's strength and experience, developing others and leaving a legacy.
Increasing Value Through Reducing Differences Between LWD and Wireline Depths
Authors: Bolt Harald
Published: September 2019

Along-hole depth is the most fundamental subsurface measurement made in our business. Driller's depth, the basis of logging while drilling (LWD) data registration, and wireline logged depth are the primary sources of along-hole depth data. These are rarely congruent. This paper sets out a methodology that can be applied to both wireline and drill pipe along-hole depth measurement (Driller's Way-point Depth, DwpD) and provides an uncertainty calculation that results in True Along-hole (TAH) depth. The result is a reduction in differences between drill pipe and wireline depth measurements, increasing confidence in along-hole depth measurements and increasing well data value. A field data set is reviewed that showed up the similarities and the differences between DwpD and the wireline corrections.
In-Situ Stresses in Colorado Group, AB, Calculated from Open-Hole Mini-Fracs and FMI Logs
Authors: Costin Simona , Smith Richard , Yuan Yanguang , Andjelkovic Dragan , Garcia Rosas Gabriel
Published: September 2019

Open-hole mini-frac tests are seldom performed in the Athabasca and Cold Lake oil sands due to the complexity of operations. In this paper we present the results of open-hole injections tests performed in Cold Lake, Alberta (AB), Canada. The objective of the injection tests was to assess the in-situ stress condition in the Cretaceous Colorado Group. The injection tests results combined with the run of formation image logs (FMI) before and after the injection have enabled not only the determination of the in-situ minimum stress in the rock, but also the full 3-D stress tensor, along with the orientation and inclination of the hydraulic fracture.

The tests were performed in IOL 102/08-02-066-03W4 (N10 Passive Seimic Well, ‘PSW’). The injection tests have revealed that the vertical stress in the area is the in-situ minimum stress, consistent with previous measurements. The hydraulically-induced fracture has sub-horizontal to moderate dip angle, mostly owing to the pre-existing fabric of the rock, and peaks in the general NE-SW direction. Numerical modeling of the in-situ stresses has shown that the values of the vertical and the minimum horizontal stresses are close, with the vertical stress consistently being smaller than the minimum horizontal stress in all tested zones.
Downhole Fluid Characterization with Validated Mapping from Optical Sensor Measurements
Authors: Chen Dingding , Jones Christopher , Dai Bin , VanZuilekom Anthony
Published: September 2019

Robust downhole fluid analysis highly relies on quality measurements and data mapping from various optical sensors implemented into modern formation testers. The direct modeling used to determine a multivariate correlation between optical sensor responses and diverse fluid compositions or properties is often cost-prohibitive with sensor-based calibration. This paper presents a novel method based on concatenated optical computing neural networks (COCN), which link sensor-specific signal transformation to generic fluid characterization through validated data mapping.

The COCN models are built separately in the in-house laboratory using optical data transformation networks and multi-analyte fluid characterization networks. To evaluate the uncertainty of sensor signal mapping, additional sensor data prediction networks, which exchange inputs and outputs of sensor data transformation networks to provide reverse data mapping, can be built to produce the simulated sensor responses. The actual sensor measurements are then compared to the simulated sensor responses to validate the optical signal transformation. The degree of matching can be used to identify issues associated with the quality of the sensor measurements and the range of calibration and testing data, and to select the transformation networks in ruggedizing predictions of fluid compositions and properties.

This paper presents the method used and case studies to exemplify the application of the proposed approach for reliable fluid sample characterization using laboratory and field measurement data. Calibrating sensor-independent fluid predictive networks on a large database usually pertains to low uncertainty because the analyzed measurements can be collected from diverse reservoir fluid samples. The construction of data transformation networks, however, is only realistic by using a small number of reference fluids because of their high calibration cost, which conversely challenges the quality of data mapping with new field sensor measurements. In this study, sensor data transformation networks and sensor data prediction networks form two groups of mutually complementing models that can validate one another, making the quality of data mapping observable before applying fluid characterization models. The results of the case studies demonstrate that the consistency between the actual and simulated sensor responses is a reasonable performance index in the prediction of fluid compositions and properties. The laboratory and field examples also justified the importance of using simulation data appropriately to overcome the limitation of sensor measurement data in the calibration of transformation networks.
Acoustic and Nuclear Wireline Logging Validation of Shape Memory Polymer Screen Expansion
Authors: Flores Juan Carlos , Patterson Douglas John , Wakefield John , Chace David , Malbrel Christophe
Published: September 2019

A new shape memory polymer (SMP) sandface completion is entering the market as an alternative to gravel packs. The SMP activation has been well established in the laboratory and successful field deployments has been reported. To confirm the SMP material is fully expanded and to enable long term stability assessment, a practical in-situ evaluation method is needed. Three acoustic and two nuclear services are evaluated for their ability to detect SMP expansion in a simulated formation.

A downhole equivalent in-situ test environment was built for purpose with a section of limestone blocks drilled to 8.5 in. gauge hole and a joint of unexpanded SMP screen placed within. Two cased-hole CBL services evaluated ultrasonic guided mode attenuation response in the base perforated pipe. These modes consisting of two lamb modes, the compressional (S0) and the asymmetric (A0 flexural), along with the shear horizontal (SH) mode. Additionally, a multipole acoustic tool was utilized to analyze the response of both the refracted modes, compressional and shear, and the guided modes, casing tube and flexural waves. Nuclear services employed pulsed neutron and compensated neutron techniques. The SMP was then activated and a second pass logged for each technique. The limestone was removed from the SMP to visually verify expansion. The logs before and after expansion are compared.

In conclusion, several measurements provided good indication of the SMP expansion. The ultrasonic guided mode analysis demonstrated attenuation response increases, with the largest change observed for the A0 mode when compared to the S0 compressional response. Of the lower frequency multipole acoustic methods, the guided casing tube wave demonstrated the greatest response, even greater than the ultrasonic, particularly in the low frequency range below 3 kHz. Generally, excitation modes with particle motion parallel with the base pipe were found to attenuate least while those with normal components displayed the largest change. This is likely due to compression of the base pipe and metal screen layers because the SMP begins to exert force in all directions when it reaches gauge hole, which is short of full expansion as designed.

The pulsed neutron (PN) logs provided a qualitative, yet clear verification of expansion when comparing measurements sensitive to hydrogen concentration. The SMP is an extremely low density organic molecule with hydrogen concentration less than that of water. Comparing before and after PN logs indicates that a change in the hydrogen concentration occurred as a result of SMP expansion. Compensated neutron did not show sensitivity to expansion of the polymer.

This is the industry’s first logging validation of shape memory polymer activation in the annulus of a simulated downhole environment. Prior attempts with a variety of logging services and a simpler test environment were inconclusive.
A Mechanistic Approach for Calculating Oil-Gas Relative Permeability Curves in Unconventional Reservoirs
Authors: Czernia Bartosz , Barrufet Maria
Published: September 2019

A mechanistic approach for calculation of oil-gas capillary pressure curves and relative permeabilities in unconventional reservoirs is presented. The approach accounts for reservoir fluid composition, contact angle wettability and pore size distribution of each specific reservoir and generates a unique set of relative permeability curves based on those inputs. This allows calculation of curves in reservoirs where historical production data is limited.

Phase behavior calculations are computed by coupling the Peng-Robinson equation of state and the Young-Laplace capillary pressure model. This coupling allows for inclusion of the effect of confinement of reservoir fluids on volumetric and transport properties.

The reservoir is modeled as a bundle of tubes with diameters representative of the pore size distribution found in the reservoir. A multi-step depletion is modeled followed by gas injection and a secondary depletion. Separate capillary pressure results are obtained for each part of the process. After the capillary pressure curves are generated, an integration is performed on the capillary results to generate a set of relative permeability curves following the Nakornthap and Evans method (1986).

The multi-step process is used to allow recalculation of the relative permeability curves as the reservoir fluid composition changes due to the initial depletion and then secondary gas injection.The approach yields a unique set of relative permeability results for each set of input parameters.The mechanistic approach is demonstrated on two different oil compositions, a black oil sample and a volatile oil. For each of the oil compositions, two different injection gasses are evaluated (methane and carbon dioxide). The intermediate calculations are summarized and the final permeability results are included in the paper. The results show that for both oil samples evaluated, the gas injection results in an increase in oil relative permeability. Carbon dioxide is more effective at increasing the oil relative permeability than methane for both oil samples. This suggests that carbon dioxide could be an effective option for enhanced oil recovery operations in unconventional reservoirs.

A unique element of the approach presented is that the calculation of relative permeability curves for the initial reservoir depletion is immediately followed by the calculation of new relative permeability curves as the reservoir composition changes due to gas injection. This allows prediction of relative permeability results in an unconventional reservoir for both the initial reservoir depletion and also for hypothetical enhanced oil recovery operations. Since the model can be run quickly and repeatedly, sensitivity analyses can be performed on the permeability curves as a function of initial reservoir conditions and injection gas compositions and amounts.
Fluid Sampling in Tight Unconventionals
Authors: Carlsen Mathias Lia , Whitson Curtis Hays , Alavian Ahmad , Martinsen Sissel Øksnevad , Mydland Stian , Singh Kameshwar , Younus Bilal , Yusra Ilina
Published: September 2019

In this paper we emphasize the duality of fluid sampling: (1) fluid characterization; to collect samples and measure pressure/volume/temperature (PVT) data that can be used to build and tune an equation of state (EOS) model, and (2) fluid initialization; to collect samples to estimate in-situ fluid compositions. It is hard, if not impossible, to obtain truly in-situ representative fluid samples in multi-fractured horizontal wells (MFHW). This paper explains why fluids measured in the lab may be significantly different from in-situ representative fluid samples, even if the fluid samples are collected shortly after the well is put online. The paper also suggests that practically all samples, in-situ representative or not, can and should be used to build a reliable EOS model.

To make a comprehensive assessment of fluid sampling in tight unconventionals, reservoir fluids ranging from black oils to gas condensates have been studied. For a wide range of fluid systems, a compositional reservoir simulator has been used to assess two main scenarios: (1) an initially undersaturated (single-phase) fluid system, and (2) initially saturated (two-phase) fluid system. To quantify how collected surface samples change with time, three properties are studied as functions of time: (1) saturation pressure and type (dewpoint | bubblepoint), (2) producing gas/oil ratio (GOR), and (3) stock-tank oil (STO) API. Observations of how these three properties change with time is used to help explain why elevated saturation pressures, greater than the initial reservoir pressure, often can be observed.

Rapid decline of the flowing bottomhole pressure (BHP | pwf), together with shut-in periods, makes it difficult to obtain in-situ representative samples in MFHW. For slightly undersaturated reservoirs, and saturated reservoirs, it may be impossible to obtain in-situ representative fluid samples because of the near-wellbore multiphase behavior. However, samples which are not in-situ representative can still be used to estimate original in-situ fluids using equilibrium contact mixing (ECM) procedures. In this paper, we propose two ECM methods that can either be carried out by physical measurements in a PVT lab or can be computed with a properly tuned EOS model.
Eliminating Guesswork in Downhole Diagnostics with Definitive Answers from Downhole X-ray Technology
Authors: Hamid Saad , Almulhim Abdulrahman A. , Achihai Radu , Spannuth Melissa
Published: September 2019

When a restriction or non-conformity presents itself in a well, quickly and reliably diagnosing the nature of the anomaly can save diagnostic runs and help prevent similar cases elsewhere, reducing nonproductive time and operating costs. Downhole X-ray diagnostics provide this understanding quickly and reliably under diverse well conditions that limit the effectiveness of other downhole diagnostic techniques. X-ray diagnostics produce real-time, quantitative two-dimensional images and three-dimensional reconstructions of downhole objects and obstructions with high precision. We demonstrate this with a case study in which X-ray diagnostics accurately identified and quantitatively characterized an obstruction due to liner deformation.
Artificial Intelligent Logs for Formation Evaluation Using Case Studies in Gulf of Mexico and Trinidad & Tobago
Authors: Gan Thomas , Kumar Ashok , Ehiwario Michael , Zhang Barry , Sembroski Charles , de Jesus Orlando , Hoffmann Olivier , Metwally Yasser
Published: September 2019

Borehole-log data acquisition accounts for a significant proportion of exploration, appraisal and field development costs. As part of Shell technical competitive scoping, there is an ambition to increase formation evaluation value of information by leveraging drilling and mudlogging data, which traditionally often used in petrophysical or reservoir modelling workflow.

Often data acquisition and formation evaluation for the shallow hole sections (or overburden) are incomplete. Logging-while-drilling (LWD) and/or wireline log data coverage is restricted to mostly GR, RES and mud log information and the quality of the logs varied depending on the vendor companies or year of the acquisition. In addition, reservoir characterization logs typically covered only the final few thousand feet of the wellbore thus preventing a full quantitative petrophysical, geomechanical, geological correlation and geophysical modelling, which caused limited understanding of overburden sections in the drilled locations and geohazards risls assessment.

Use of neural networks (NN) to predict logs is a well-known in Petrophysic discipline and has often used technology since more than last 10 years. However, the NN model seldon utilized the drilling and mudlogging data (due to lack of calibration and inconsistency) and up until now the industry usually used to predict a synthetic log or fill gaps in a log. With the collaboration between Shell and Quantico, the project team develops a plug-in based on a novel artificial intelligence (AI) logs workflow using neural-network to generate synthetic/AI logs from offset wells logs data, drilling and mudlogging data. The AI logs workflow is trialled in Shell Trinidad & Tobago and Gulf of Mexicooffshore fields.

The results of this study indicate the neural network model provides data comparable to that from conventional logging tools over the study area. When comparing the resulting synthetic logs with measured logs, the range of variance is within the expected variance of repeat runs of a conventional logging tool. Cross plots of synthetic versus measured logs indicate a high density of points centralized about the one-to-one line, indicating a robust model with no systematic biases. The QLog approach provides several potential benefits. These include a common framework for producing DTC, DTS, NEU and RHOB logs in one pass from a standard set of drilling, LWD and survey parameters. Since this framework ties together drilling, formation evaluation and geophysical data, the artificial intelligence enhances and possibly enables other petrophysical/QI/rock property analysis that including seismic inversion, high resolution logs, log QC/editing, real-time LWD, drilling optimization and others.
Using Nanoparticles Coating to Enhance Proppant Functions to Achieve Sustainable Production
Authors: Tabatabaei Maryam , Dahi Taleghani Arash , Cai Yuzhe , Yang Santos Livio , Alem Nasim
Published: September 2019

Proppant bed plays a critical role in enhancing oil and gas production in stimulated wells. In the last two decades, there have been consistent efforts to improve shape characteristics and mechanical strength properties to guarantee high permeability in the resultant propped fracture. However tuning wettability of proppants have not yet engineered considerably maybe because natural sand has been a typical raw material for proppant manufacturing. However, water wet proppants may not only limit production due to reduced hydrocarbon relative permeability but also facilitate fine migration through the proppant bed. Fine migration and increasing water saturation may deteriorate oil production over time. Intrinsic hydrophobicity of graphitic surfaces and their two-dimensional geometries made them a promising candidate for coating proppant to alter its wettability. In this paper, we present a methodology for treating proppant surfaces with graphite nanoplatelets. Standard laboratory tests following modified API RP61 have conducted to show the effectiveness of the proposed methodology.
Method of Determining Unconventional Reservoir Saturation with NMR Logging
Authors: Ye Shin-Ju , Scribner Allison , McLendon Darren , Ijasan Olabode , Chen Songhua , Shao Wei , Balliet Ron
Published: September 2019

Nuclear magnetic resonance (NMR) T1-T2 logs from several west Texas wells over various formation layers were acquired to assess the values of NMR logging for fluid typing and saturation quantification in tight mudstone reservoirs. To quantify fluids in those low-porosity formations, high-density NMR data with adequate signal-to-noise ratio (SNR) are essential, and an inversion algorithm capable of resolving fluids on T1-T2 map is needed. These requirements are achieved with multifrequency data acquisition having a short interecho spacing (TE) for all frequencies, which yields a total of 15,400 echoes per depth in a single NMR pulse sequence cycle. This large data density enables less vertical averaging to be needed in both 1D and 2D processing, which is essential for capturing the porosity and fluid volume variation in these layered formations. The use of the inversion-forward modeling-inversion (IFMI) method improves the spectral resolution of the relaxation time distribution and T1-T2 map resolution because the method adequately addresses the effect of gradient differences in NMR responses in multifrequency data acquisition. 2D T1-T2 map fluid resolution of downhole stations and moving logs are compared to determine the minimal stacking required for fluid discrimination. The porosity and water volume are compared with those of conventional and mineralogy logs.
Successful Application of Homogenization Principle in ESPs: Case Study in South America
Authors: Gonzalez Gustavo , Guanacas Luis , Pinto Diego , Montufar Carlos
Published: September 2019

Sand management has become in one of the most vital factors in today's upstream oil and gas industry, more and more are the cases where the sand control systems play an important factor to determine the economic viability of each project. This paper will focus in a solution for sand problems in ESP systems applying to sand slug breakdown using a 10 V-Mesh Sand Screen to homogenize the solid inflow in the system so it would be easier to handle the solids through the ESP's stages. The implementation of the screen intake for the homogenization of solids in an ESP well allowed to efficiently manage sand slugs, improving the pump efficiency and avoiding blocking problems in the pump caused by sand. Furthermore, the system allows increasing the frequency of operation of the ESP motor to have a greater drawdown, increasing the production of the fluid from 1600 BFPD to 1800 BFPD. The behavior of the sensor data such as vibration, current, and voltage remained stable throughout the period evaluated, extending the run life of the system.
Unconventional Reservoirs Next Frontier: Efficient Production Modeling – Part 2
Authors: Ayoub Joseph , Krishnamurthy Shalini , Gao Sunhua , Jimenez Jose , Thambynayagam Michael
Published: September 2019

A novel analytical-numerical hybrid model introduced in SPE 1914441 is used to illustrate through example applications the benefit of having physics-based models that are practical for automation and integration with monitoring and control systems. The solution integrates the reservoir, completion and surface network, resulting in an efficient model that is readily accessible for daily production optimization. It makes a digital twin for every unconventional well affordable by extensive automation and efficient interface enabling management by exception. In this paper, additional example applications complementing those discussed in SPE 191444 are presented. They include optimization of well-hydraulic fractures positioning in multilayer environment and a quantitative discussion of co-linear versus transverse fracture designs and of the benefits of gas lift optimization. The aim is to illustrate the need/utility for a fast, integrated model that can be used to assist in optimizing the completion and that carry over to production enabling daily production optimization that is practical as opposed to solutions that are too onerous to deploy for every well throughout its lifecycle.
Optimization of Steam-Additive Processes With DTS/DAS Applications in Heavy Oil Reservoirs
Authors: Temizel Cenk , Irani Mazda , Ghannadi Sahar , Canbaz Celal Hakan , Moreno Raul , Bashtani Farzad , Basri Mustafa A.
Published: September 2019

DTS/DAS applications provide key advantages in surveillance and better understanding of both unconventional and thermal operations in terms of key attributes including but not limited to conformance, wellbore integrity in better spatial and temporal terms. This study investigates the effects of CO2 in enhancing the steamflood process while incremental benefits are achieved through improved monitoring of the steamflood injection process using DTS/DAS applications using a completely synthetic but realistic reservoir model.

A full-physics reservoir simulator is used to model the process. The technical and economic details of deployment of DTS/DAS as well as the steam-additive process are outlined in detail. Sensitivity study carried out on the model indicates the key attributes along with their significance. Athabasca bitumen properties are used. CO2 additive increases the steam chamber size but lowers the steam temperature while naptha/CO2 additives lower the viscosity, thus optimization study carried out the optimum operating levels of the additives not only in physical production/injection terms but also in terms of economics.

The results indicate better reservoir management with DTS/DAS applications compared to the base case and injection can be monitored and adjusted better with such tools. DTS/DAS applications prove useful not only in terms of production performance but also in terms of economics. Physical properties of CO2 and naptha outline that the two have different dominant modes of improving recovery with steam-only injection. CO2 increases the extent of the steam chamber while lowering the steam temperature significantly.

This study approaches the delicate process of additive use in steam processes while coupling the additional benefits of use of DTS/DAS applications in optimizing the recovery and the economics outlining the key attributes and the challenges and best practices in operations serving as a thorough reference for future applications.