bluuebunny/crossref_metadata_2025 huggingface dataset:
Experimental Investigation of the Impact of Crude Oil and Rock on Improved Recovery by Low Salinity Water Injection
Authors: Alhammadi Mohamed , Masalmeh Shehadeh Masalmeh , Al-Shehhi Budoor , Sohrabi Mehran , Farzaneh Amir
Published: September 2021

This study aims to compare the roles of rock and crude oil in improving recovery by low salinity water injection (LSWI) and, particularly, to explore the significance of micro-dispersion formation in LSWI performance. Core samples and crude oil were taken from two carbonate reservoirs (A and B) in Abu Dhabi. The oil samples were selected such that one of them would form micro-dispersion when in contact with low salinity brine while the other would not.

A series of coreflood experiments was performed in secondary and tertiary modes under reservoir conditions. First, a core sample from reservoir A was initialized and aged with crude oil from reservoir A and a core sample from reservoir B was initialized and aged with crude oil from reservoir B. The cores were then swapped, and the performance of low salinity injection was tested using rock from reservoir A and crude from reservoir B, and vice versa.

For the first set of experiments, we found that the crude oil sample capable of forming micro-dispersion (we call this oil "positive", from reservoir A) resulted in extra oil recovery in both secondary and tertiary LSWI modes, compared to high salinity flooding. Moreover, in the secondary LSWI mode we observed significant acceleration of oil production, with higher ultimate oil recovery (12.5%) compared to tertiary mode (6.5%). To ensure repeatability, the tertiary experiment was repeated, and the results were reproduced. The core flood test performed using "negative" crude oil that did not form micro-dispersion (from reservoir B) showed no improvement in oil recovery compared to high salinity waterflooding. In the "cross-over" experiments (when cores were swapped), the positive crude oil showed a similar improvement in oil recovery and the negative crude oil showed no improvement in oil recovery even though each of them was used with a core sample from the other reservoir. These results suggest that it is the properties of crude oil rather than the rock that play the greater role in oil recovery. These results suggest that the ability of crude oil to form micro-dispersion when contacted with low salinity water is an important factor in determining whether low salinity injection will lead to extra oil recovery during both secondary and tertiary LSWI. The pH and ionic composition of the core effluent were measured for all experiments and were unaffected by the combination of core and oil used in each experiment.

This work provides new experimental evidence regarding real reservoir rock and oil under reservoir conditions. The novel crossover approach in which crude oil from one reservoir was tested in another reservoir rock was helpful for understanding the relative roles of crude oil and rock in the low salinity water mechanism. Our approach suggests a simple, rapid and low-cost methodology for screening target reservoirs for LSWI.
Simulating Multiphase Flow in Reservoirs with Generative Deep Learning
Authors: Alakeely Abdullah A. , Horne Roland N.
Published: September 2021

This study investigated the ability to produce accurate multiphase flow profiles simulating the response of producing reservoirs, using Generative Deep Learning (GDL) methods. Historical production data from numerical simulators were used to train a GDL model that was then used to predict the output of new wells in unseen locations.

This work describes a procedure in which data analysis techniques are used to gain insight into reservoir flow behavior at a field level based on existing historical data. The procedure includes clustering, dimensionality reduction, correlation, in addition to novel interpretation methodologies that synthesize the results from reservoir simulation output, characterizing flow conditions. The insight was then used to build and train a GDL algorithm that reproduces the multiphase reservoir behavior for unseen operational conditions with high accuracy. The trained algorithm can be used to further generate new predictions of the reservoir response under operational conditions for which we do not have previous examples in the training data set.

We found that the GDL algorithm can be used as a robust multiphase flow simulator. In addition, we showed that the physics of flow can be captured and manipulated in the GDL latent space after training to reproduce different physical effects that did not exist in the original training data set. Applying the methodology to the problem of determining multiphase production rate from new producing wells in undrilled locations showed positive results. The methodology was tested successfully in predicting multiphase production under different scenarios including multiwell channelized and heterogeneous reservoirs. Comparison with other shallow supervised algorithms demonstrated improvements realized by the proposed methodology, compared to existing methods.

The study developed a novel methodology to interpret both data and GDL algorithms, geared towards improving reservoir management. The method was able to predict the performance of new wells in previously undrilled locations without using a reservoir simulator.
Engineers of the Future: Student Training Program for the New Business Model
Authors: Maksyutin Konstantin , Zalevina Anna , Sorokin Pavel , Rukavishnikov Valeriy , Boev Artem , Kharitontseva Polina , Solovev Vasilii , Portniagina Arina , Lukin Alexey
Published: September 2021

A major Russian oil company is currently carrying through an ambitious program aimed at transforming corporate E&P business model. The new model involving product-based approach to exploration and production will require young professionals with new skills and mindsets beyond regular university curricula. To proactively satisfy this demand, the company joined forces with one of its partner universities to champion Engineers of the Future, a training initiative aimed at senior students about to graduate and join the company.

Engineers of the Future offer a fresh perspective and approach to training young professionals, mixing conventional training with problem-based and game-based learning to deliver a unique combination of hard and soft skills required by company's new operating paradigm. Program graduates are expected to make a great addition to corporate product teams, enabling the company to achieve its challenging strategic goals.
A Data-Driven Approach to Predict the Breakdown Pressure of the Tight and Unconventional Formation
Authors: Tariq Zeeshan , Aljawad Murtada Saleh , Murtaza Mobeen , Mahmoud Mohamed , Al-Shehri Dhafer , Abdulraheem Abdulazeez
Published: September 2021

Unconventional reservoirs are characterized by their extremely low permeabilities surrounded by huge in-situ stresses. Hydraulic fracturing is a most commonly used stimulation technique to produce from such reservoirs. Due to high in situ stresses, breakdown pressure of the rock can be too difficult to achieve despite of reaching maximum pumping capacity. In this study, a new model is proposed to predict the breakdown pressures of the rock. An extensive experimental study was carried out on different cylindrical specimens and the hydraulic fracturing stimulation was performed with different fracturing fluids. Stimulation was carried out to record the rock breakdown pressure. Different types of fracturing fluids such as slick water, linear gel, cross-linked gels, guar gum, and heavy oil were tested. The experiments were carried out on different types of rock samples such as shales, sandstone, and tight carbonates. An extensive rock mechanical study was conducted to measure the elastic and failure parameters of the rock samples tested. An artificial neural network was used to correlate the breakdown pressure of the rock as a function of fracturing fluids, experimental conditions, and rock properties. Fracturing fluid properties included injection rate and fluid viscosity. Rock properties included were tensile strength, unconfined compressive strength, Young's Modulus, Poisson's ratio, porosity, permeability, and bulk density. In the process of data training, we analyzed and optimized the parameters of the neural network, including activation function, number of hidden layers, number of neurons in each layer, training times, data set division, and obtained the optimal model suitable for prediction of breakdown pressure. With the optimal setting of the neural network, we were successfully able to predict the breakdown pressure of the unconventional formation with an accuracy of 95%. The proposed method can greatly reduce the prediction cost of rock breakdown pressure before the fracturing operation of new wells and provides an optional method for the evaluation of tight oil reservoirs.
Importance of 3-Way Coupled Modelling for Carbon Dioxide Sequestration in Depleted Reservoir
Authors: Chidambaram Prasanna , Tiwari Pankaj Kumar , Patil Parimal A , Mohd Ali Siti Syareena , M Amin Sharidah , Tewari Raj Deo , Tan Chee Phuat , Widyanita Ana , B A Hamid M Khaidhir
Published: September 2021

Carbon sequestration is the process of capturing and storage of atmospheric carbon dioxide. The objective of any carbon sequestration project is to store CO2 safely for hundreds or thousands of years with a goal of reducing global climate change. A depleted hydrocarbon reservoir is one of the potential storage sites being considered for long-term CO2 storage. The dynamic, geochemical, and geomechanics changes that occur during CO2 injection are inter-related. For example, when injected CO2 causes dissolution of reservoir rock, on one hand, porosity increases while rock strength decreases. On the other hand, reduced rock strength could cause additional compaction thus reducing porosity, whereas increase in pressure due to injection could cause dilation. Hence, it is critical to have an integrated model that captures effect of all changes on the storage capacity and integrity of the reservoir.

Three major depleted gas reservoirs in Central Luconia field, located offshore Sarawak, are being evaluated for future CO2 storage. A 3-way coupled modelling approach that integrates dynamic model, geochemistry model, and geomechanics model is utilized to obtain cumulative effect of all three changes. This integrated model provides a more accurate estimate of 1) CO2 storage capacity, 2) Caprock integrity evaluation, 3) CO2 plume migration path, and 4) Volume of CO2 stored through different storage mechanisms (viz. hydrodynamic trapping, capillary trapping, solubility trapping, and mineral trapping). Apart from providing storage capacity, this model also provides inputs for evaluating integrity of caprock, fault reactivation study, MMV (Measurement, Monitoring, and Verification) planning, and estimating potential leak rates through plugged and abandoned wells.

Using a 3-way coupled model, it is estimated that there is an average reduction in porosity of 5-10% (of initial porosity). This translates to an equivalent reduction in CO2 storage capacity of 5-10% compared to dynamic model. It is observed that pore collapse as a result of pressure depletion is primarily responsible for this reduction in porosity. It has also been observed that the injection can be continued till initial reservoir pressure is reached without breaching caprock integrity. CO2 plume migration path significantly affects MMV planning. Potential leak rate estimation is critical in mitigation and contingency planning.
4D Seismic in Subsurface CO2 Plume Monitoring – Why It Matters?
Authors: Tiwari Pankaj Kumar , Das Debasis Priyadarshan , Patil Parimal Arjun , Chidambaram Prasanna , Chandran Prasanna Kumar , Tewari Raj Deo , Abdul Hamid M Khaidhir
Published: September 2021

CO2 sequestration in depleted carbonate reservoir stipulate incorporation of comprehensive and trailblazing monitoring technologies. 4D time-lapse seismic is sine qua non for Monitoring, Measurement and Verification (MMV) planning to demonstrate the migration of CO2 plume within geological storage. An ingenious, adaptive and site specific MMV plan for monitoring CO2 plume is paramount to minimize possible subsurface and project integrity risks. Integration of dynamic simulation with seismic forward modeling aggrandize the capabilities of 4D seismic in CO2 sequestration projects.

Depleted carbonate reservoir has been thoroughly studied and its geomechanical and geochemical modeling results were coupled into dynamic simulation. Reservoir porosity and fluid properties along with CO2 saturation and injection pressure distribution within each reservoir level were generated. The dynamic simulation results were integrated with seismic forward modeling to demonstrate the CO2 plume migration and its impact on seismic amplitude. Fluid acoustic properties were computed for carbonate reservoir using FLAG method. Selection of wells was based on availability of superior quality acoustic logs as well as those representing the reservoir best. Gassmann fluid substitution exercise was carried using dry rock modeling. Several scenarios were generated, and results were analyzed to demonstrate the effect of CO2 saturation and pressure build-ups within reservoir on the seismic amplitude due to continuous CO2 injection.

Synthetic seismic AVO gathers were generated for angles ranging from 5 to 50 degree. Near, Mid and Far seismic amplitude response at the top of carbonate reservoir were analyzed with respect to in-situ condition for each scenario. Results reveal that CO2 saturation as low as 25 - 30% in depleted carbonate reservoir can be distinguished from 4D time-lapse seismic. With continuous CO2 injection, the reservoir pressure increases and this in turn controls the properties of both in-situ and injected fluids. The gradual changes in fluid properties and their impact on bulk acoustic properties of reservoir were modeled to assess the feasibility of using 4D seismic as a predictive tool for detection of localized and provincial pressure build-ups. Modeling results show that although observed changes in amplitude on synthetic gathers were subtle, it is expected that 4D seismic with high signal-to-noise ratio possibly be able to image such localized pressure build-ups. To monitor CO2 plume migration as well as localized pressure build-ups, we recommend acquiring multi-azimuth (MAZ) surface seismic in combination with 3D DAS-VSP for superior subsurface imaging. The integrated modeling approach ensures that 4D Seismic in subsurface CO2 plume monitoring is robust. Monitoring pressure build-ups from MAZ surface seismic and 3D DAS-VSP will reduce the associated risks.
Deployment of Downhole Hydraulic Lubricator Valve Enables Safe and Efficient Perforating and Production Testing Strategy – Case Study in Jambaran High Rate Gas Field, Indonesia
Authors: Rena Rahmawan , Robb Ewan , Maulana Ibnu , Batubara Aswin , Yulia Yulia , Wagianto Wagianto
Published: September 2021

This paper details the first implementation of a deep-set downhole hydraulic lubricator valve (DHLV) in Indonesia. This application was implemented in Jambaran field, onshore Central Java as part of Jambaran-Tiung Biru (JTB) national strategic project. Jambaran is a large carbonate gas field development located in proximity to densely populated areas. Since the field's reservoir contains significant concentrations of CO2 and H2S, it was important to design the completions to be able to perforate and test the wells safely without endangering the surrounding area.

To produce as per reservoir management strategy, 800 ft of reservoir section drainage was required. Multiple completion designs were considered in the initial stages which included consideration of an open hole completions design, multiple wireline perforating runs and a cased hole live well single trip coiled tubing gun system. The rigless single trip coiled tubing gun deployment system was chosen due to safety and efficiency factors. With a deep set DHLV as the primary barrier in controlling the wells following perforating substantial daily rental cost savings can be realized during perforating operations.

JTB field was developed by drilling 5 new well plus 1 re-entry well. The completions design was similar in all 6 wells. A 2 step completion design was utilized, to compensate for life of well tubing movement load, this consisted of a polished bore receptacle and production packer assembly in the lower completion. The 2nd stage of the completion consisted of 7" × 5-1/2" tubing with Tubing Retrievable Safety Valve (TRSV), DHLV, Permanent Downhole Gauge (PDHG) and production seal assembly. Strategically placing the PDHG below the DHLV enabled monitoring of bottom hole pressure during shut in without use of memory gauges validating the DHLV as primary barrier during gun retrieval. The production seal assembly was tied back into the lower polished bore receptacle that was previously set.

The deep-set DHLV enabled the operator to (i) safely run long TCP gun assemblies up to 911 ft of gross gun length per well to perforate the whole well in 1 trip, (ii) POOH guns efficiently with one time bleed off (iii) efficiently initiate the pressure build up phase by shutting in the well against the DHLV as opposed to a surface valve prior to flowing the well and (iv) gun assemblies retrieved without the need to kill the well.

After completing and well testing all 6 wells, the benefits of implementing the deep-set DHLV was immediately realized. By perforating underbalanced, omitting the well kill process and immediately proceeding with pressure build up by closing the DHLV resulted in operator savings of approximately 1.5 million USD over the entire rigless completion campaign.
A Superior Shale Oil EOR Method for the Permian Basin
Authors: Downey Robert , Venepalli Kiran , Erdle Jim , Whitelock Morgan
Published: September 2021

The Permian Basin of west Texas is the largest and most prolific shale oil producing basin in the United States. Oil production from horizontal shale oil wells in the Permian Basin has grown from 5,000 BOPD in February, 2009 to 3.5 Million BOPD as of October, 2020, with 29,000 horizontal shale oil wells in production. The primary target for this horizontal shale oil development is the Wolfcamp shale. Oil production from these wells is characterized by high initial rates and steep declines. A few producers have begun testing EOR processes, specifically natural gas cyclic injection, or "Huff and Puff", with little information provided to date. Our objective is to introduce a novel EOR process that can greatly increase the production and recovery of oil from shale oil reservoirs, while reducing the cost per barrel of recovered oil.

A superior shale oil EOR method is proposed that utilizes a triplex pump to inject a solvent liquid into the shale oil reservoir, and an efficient method to recover the injectant at the surface, for storage and reinjection. The process is designed and integrated during operation using compositional reservoir simulation in order to optimize oil recovery. Compositional simulation modeling of a Wolfcamp D horizontal producing oil well was conducted to obtain a history match on oil, gas, and water production. The matched model was then utilized to evaluate the shale oil EOR method under a variety of operating conditions. The modeling indicates that for this particular well, incremental oil production of 500% over primary EUR may be achieved in the first five years of EOR operation, and more than 700% over primary EUR after 10 years. The method, which is patented, has numerous advantages over cyclic gas injection, such as much greater oil recovery, much better economics/lower cost per barrel, lower risk of interwell communication, use of far less horsepower and fuel, shorter injection time, longer production time, smaller injection volumes, scalability, faster implementation, precludes the need for artificial lift, elimination of the need to buy and sell injectant during each cycle, ability to optimize each cycle by integration with compositional reservoir simulation modeling, and lower emissions.

This superior shale oil EOR method has been modeled in the five major US shale oil plays, indicating large incremental oil recovery potential. The method is now being field tested to confirm reservoir simulation modeling projections. If implemented early in the life of a shale oil well, its application can slow the production decline rate, recover far more oil earlier and at lower cost, and extend the life of the well by several years, while precluding the need for artificial lift.
Enhancing Hydrocarbon Production Through Thermal Gas Injection from a Retrograde as Condensate Reservoir in the Western Desert in Egypt
Authors: Taha Maged Alaa , Shokier Eissa , Attia Attia , Yahia Aamer , Mansour Khaled
Published: September 2021

In retrograde gas condensate reservoirs, condensate blockage is a major reservoir damage problem, where liquid is dropped-out of natural gas, below dew-point pressure. Despite that most of this liquid will not produce due to not reaching the critical saturation, natural gas will be blocked by the accumulated liquid and will also not produce.

This work investigates the effects of gas injection (such as methane, carbon-dioxide, and nitrogen) and steam at high temperatures on one of the Egyptian retrograde gas condensate reservoirs. Several gas injection scenarios that comprise different combination of gas injection temperature, enthalpy, injection gas types (CO2, N2, and CH4), and injection-rates were carried out.

The results indicated that all conventional and thermal gas injection scenarios do not increase the cumulative gas production more than the depletion case. The non-thermal gas injection scenarios increased the cumulative condensate production by 8.6%. However, thermal CO2 injection increased the condensate production cumulative by 28.9%.

It was observed that thermal gas injection does not vaporize condensate It was observed that thermal gas injection does not vaporize condensate more than conventional injection that have the same reservoir pressure trend. However, thermal injection mainly improves the condensate mobility. Appropriately, thermal injection in retrograde reservoirs, is mostly applicable for depleted reservoirs when the largest amount of non-producible liquid is already dropped out. Finally, this research studied executing thermal gas injection in retrograde gas condensate reservoirs, operationally, by considering the following items: carbon dioxide recovery unit, compressors, storage-tanks, anti-corrosion pipe-lines and tubing-strings, and corrosion-inhibitors along with downhole gas heaters.
Computational Fluid Dynamics for Gas Lift Optimization in Highly Deviated Wells
Authors: Sajjad Farasdaq , Chandra Steven , Wirawan Alvin , Dewi Rahmawati Silvya , Santoso Michelle , Suganda Wingky
Published: September 2021

In the implementation of gas lift, understanding flow behavior in highly-deviated well is critical in avoiding production loss due to liquid fallback and blockage, even in highly-productive reservoir. In this work, we utilize Computational Fluid Dynamics (CFD) to optimize gas lift design under various flow behavior in highly-deviated well. The analysis is directly implemented into Arjuna offshore field case.

Arjuna offshore field has gas-lifted wells, producing from a high-permeability reservoir. However, several wells suffer from huge production loss due to the effect of well's deviation. In deviated well, there exists frequent liquid fallback causes blockage, therefore, reducing the production. Motivated by this issue, we use CFD framework to perform gas lift optimization.

We firstly adopt the geometry of gas-lifted wells as the computational domains for our simulation. An image-based meshing technique is deployed to capture the well's trajectory and internal geometry. We secondly utilize compressible Navier-Stokes equation and Finite Volume Method to evaluate the flow behavior. We capture the location of liquid fallback and liquid accumulation at elbows to estimate production loss. We consider the variation of viscosity, density, gas lift valve placement, injected gas rate, and reservoir pressure. We finally perform gradient-based optimization utilizing production loss as the objective function to obtain optimum design. The final result is then used to optimize the current design.

The simulation results show that productivity index, pipe diameter, and deviation heavily influence the amount of production loss. At big pipe diameter and high deviation, the gravitational force governs the fluid flow. Therefore, slugs are developed and accumulated at elbows. This accumulation blocks gas flow and reduces production.

Changing the gas injection rate affects the lifted density. High injection rate triggers segregation between the liquid and gas, while low injection rate does not reduce the liquid density. Shifting the gas lift valve placement influence the mixing between the liquid and gas. It also determines the cost of gas injection. Hence, we need to optimize both parameters at once.

Six of thirty wells in Arjuna field experience severe liquid fallback, therefore, the production significantly decreases. The simulation shows up to 40% coverage of the pipe internal diameter, which blocks the gas flow. We perform the optimization by shifting the gas lift valve placement and adjusting the gas injection rate. By implementing the study result into the field case, we manage to improve the production by 20%.

We provide an effective way to connect high-resolution simulation to the field design and revise the current concept in designing gas lift well completion. The simulation allows engineers to provide more insight on flow assurance in highly deviated wells.
The Innovative Integration of Wellbore Strengthening and Managed-Pressure Drilling Redraw the Line Between Undrillable and Drillable - Case Study from Offshore Mediterranean Deepwater
Authors: El-Husseiny Mahmoud , El-Fakharany Taher , Khaled Samir
Published: September 2021

Managed pressure drilling (MPD) has a reputation for enhancing drilling performance. However, in this study, we use it as a technology for making undrillable wells drillable.

In the deepwater of the Mediterranean of Egypt, a gas field has been producing for few years. Water broke through in one well, thus, we must drill a new well to compensate for the reduction in production. Years of production led to pressure depletion, which makes it difficult to drill this well conventionally.

In this study, we will discuss the combination of MPD and wellbore strengthening (WS). In addition, we will discuss the challenges we met while drilling and how we tackled them, and the best practices and recommendations for similar applications.

The 12¼" × 13½" hole section passed depleted sands, followed by a pressure ramp. First, we drilled the depleted sands and confirmed the pressure ramp top. To strengthen the sand, we spotted a stress-cage pill of 645 bbls with a total concentration of 29 ppb. In addition, we conducted a formation integrity test (FIT), but its value was lower than the required value to drill to the section target depth (TD). Then, we switched to MPD and increased the mud weight. MPD in annular pressure control mode (AP) enabled us to walk the edge as near as possible to the impossible. Drilling this section was challenging due to the narrow mud weight window (MWW). We faced kick-loss cycles, where we had high-gas levels (from 20% to 55%) while drilling with a loss rate from 60 to 255 bph, at the same time.

The 8½″ × 9½″ hole section will cover a depleted reservoir. Therefore, we decided to use the MPD to drill this section. To widen the MWW, we decided to stress-caging the hole, as we drill. We loaded the active-mud system with stress-cage materials totaling 39 ppb. We drilled the hole section while keeping the bottom hole pressure (BHP) at 14.6 ppg. We drilled using MPD by maintaining 525-psi surface back pressure (SBP). We used the SBP mode (semi-auto mode) to add connections, resulting in minor background gases and minor losses.

This study discusses the application of a novel combination of MPD and WS. It emphasizes how MPD can integrate with other technologies to offer a practical solution to future drilling challenges in deepwater-drilling environments.
Khuff and Pre-Khuff Reservoir Fracture Characterization using the Cross Dipole Shear Wave Imaging and Borehole Imaging Data Integration
Authors: Menon Pradeep , Swedan Tarek , Jan Kamran , Al-Shehhi M. S. , Kieduppatum Piyanuch , Bouzida Yasmina , Cazeneuve Adrian Eduardo , Zhunussova Gulzira , Uluyuz Sila , Telang Viraj
Published: September 2021

Increasing demands for gas in UAE have led to increased focus on more tight gas reservoirs like Khuff and pre-Khuff formations, away from the conventional oil-bearing carbonate reservoirs. The case study presented is in an offshore field, Northwest of Abu Dhabi city. The structure, with an area of 50 Sq.km was first identified in 1966 and it is part of the regional N-S extending structural.

The multi-discipline approach applied in this study required the integration of a suite of open-hole data over a variety of length scales. Combination of the Borehole Acoustic Reflection Imaging technique and borehole imaging logs (BHI) in 3D, provides a better understanding of the complex fracturing network and the associated formation stress orientation up to 100ft away from the wellbore. The ability to "see" away from wellbore what was previously hidden on seismic, allows unlocking further potential reserves or avoiding certain production hazards.

The well has penetrated the highly economical tight clastic Pre-khuff formation and the carbonate Kuff formation, allowing the analysis over a large geological history of offshore Abu Dhabi. The coherency of all data has helped establish for the first time a baseline understanding of the role of the fractures and fault in the petrophysical properties distribution along the wellbore and the 3D structural characterization in an larger area around the wellbore (up to 100ft).

The emphasize in this paper is on the Borehole Acoustic Reflection Imaging technique (DSWI), which allows the identification of both intersecting and non-intersecting of geological features with a depth of investigation up to 100 ft away from the borehole. Moreover, the combination of DSWI with BHI have been used for the anisotropy estimation away from wellbore especially in a very tight and fractured reservoir deciphering multiple fault orientation, which potentially, cancel the anisotropy estimation due to destructive interference. In addition to the presence of drilling induced fractures interfering in with the natural fracture as seen on the BHI.

The detailed BHI interpretation and the petrophysical data revealed that the fracture densities and orientation vary from bottom to top interval indicating tectonic regimes affecting the field. The lithological variation due to the evolution of the depositional setting has significantly influenced the fracture distribution and their length.

The presence of these induced fractures and how deep they propagate into the formation, dominates the behavior acoustic anisotropy by reaching the flexural (dipole shear) investigation zone (3 to 4ft deep). It is also interesting to see the behavior of both natural and induced fractures and their respective strike change over the different formations revealing a geomechanically complex structure.
Eliminating Diffusion Effects from NMR Logging Data for Enhanced Carbonate Pore Typing
Authors: Hursan Gabor , Shao Wei , Balliet Ron , Farooq Yasir
Published: September 2021

Transverse relaxation (T2) times measured by multi-frequency, multi-gradient nuclear magnetic resonance (NMR) logging tools are affected by diffusion-induced enhanced relaxation which reduces the sensitivity to pore size in slow-relaxing formations such as macroporous carbonates and complicates the integration with zero-gradient core NMR data. We propose a solution for eliminating the diffusion-related uncertainties using intrinsic T2 distributions, obtained by a new inversion-forward modeling-inversion (IFMI) method, for carbonate pore typing applications.

The NMR logs presented in this paper are based on data measured at five frequencies where the static magnetic field gradient varies from 26 to 55 G/cm. The high-quality echo signals are processed using a three-step IFMI differential signal analysis approach which nullifies diffusion effects due to the tool gradient and the potentially present internal gradient caused by paramagnetic minerals in the formation. The resulting diffusion-free intrinsic T2 distribution accentuates fine pore size variations and allows better discernment of micro-, meso-, and macropore systems of complex carbonate reservoirs.

Multi-frequency NMR data, acquired in multiple wells, were processed and analyzed in several ways. First, apparent T2 distributions were obtained separately for individual frequencies. Discrepancies between the results of different frequencies clearly indicated that in macro- and mesoporous carbonates the diffusion effect is significant even with TE=0.3ms. This leads a peak broadening observed in the apparent T2 spectrum from conventional NMR processing, where echo trains from different frequencies are averaged in time-domain prior to the inversion. With the IFMI processing, individual-frequency echo trains are first pre-processed using a 2D NMR inversion whose results are used to forward model a diffusion-free echo train without prior assumptions on reservoir fluid diffusivity D. A second inversion, applied on the diffusion-free echo train, yields the intrinsic T2 distribution. The intrinsic T2 distribution has a noticeably higher spectral resolution in carbonate formations where diffusion effect is significant. The intrinsic T2 logs are expected to be more consistent with other gradient-free NMR measurements such as core NMR or LWD NMR data sets.
Comprehensive Fracture Characterization in Tight Carbonate Reservoir Using LWD High-Resolution Image and Multi-Pole Sonic Measurement; A Case Study from Offshore North West Java, Indonesia
Authors: Irawan Debby , Wibowo Icuk Dwi , Martinauly Bertha , Fransiska Linda , Lilasari Leonora Ludwina , Permanasari Dian , Jhonny Jhonny
Published: September 2021

Tapping into an unconventional reservoir such as naturally fractured tight carbonate or basement has become more common in the industry. Open natural fractures, when present are the major contributor to production flow in such formation. Therefore, a comprehensive understanding of fracture properties including aperture, intensity, and permeability is required to identify the productive fractures and optimize production.

In this paper, we discuss the first application of the latest Logging-While Drilling (LWD) high-resolution laterolog resistivity image in combination with LWD multi-pole sonic to provide comprehensive fracture characterization in Pre-Talang Akar Formation tight carbonate reservoir, in the offshore North West Java Basin, Indonesia. The methodology involved identification of borehole breakouts, natural or drilling-induced fractures, faults and vugs from the high-resolution LWD image data, which were then interpreted further to provide the fracture attributes and the secondary porosity distributions from each of the identified features. The Stoneley measurement from LWD multi-pole sonic log enabled the analysis of the fracture system producibility using the sonic fracture technique. The characterization of fractures and faults (open/closed) from the integration of these two independent methods were complemented by the triple combo measurements, caliper, and drilling loss data, as well as sonic compressional and shear data.

This methodology has successfully managed to differentiate open fracture zones and closed fracture zones along with their computed fracture properties. The open fracture zones were characterized by a cluster of conductive fractures with large fracture aperture and fracture porosity value. These fractures were also associated with positive fracture indication from the sonic data, decrease in density logs, shallow - deep resistivity log separation and drilling loss occurrence. Whereas, closed fracture zones were characterized with minor fracture dip development. It also showed negative open fracture indication from sonic data, flat density log response and overlaying resistivity log response with no drilling loss occurrence.

The case study in this paper shows excellent LWD data quality and fracture characterization result, on par with wireline conveyed data that were commonly used to quantify fracture attributes. The results provide invaluable information for volumetric calculation, well completion and production planning in this area.
History Matching and Performance Prediction of a Polymer Flood Pilot in Heavy Oil Reservoir on Alaska North Slope
Authors: Wang Xindan , Keith Cody , Zhang Yin , Dandekar Abhijit , Ning Samson , Wang Dongmei , Edwards Reid , Barnes John , Girbacea Radu , Cercone David , Ciferno Jared
Published: September 2021

The first-ever polymer flood pilot to enhance heavy oil recovery on Alaska North Slope (ANS) is ongoing. After more than 2.5 years of polymer injection, significant benefit has been observed from the decrease in water cut from 65% to less than 15% in the project producers. The primary objective of this study is to develop a robust history-matched reservoir simulation model capable of predicting future polymer flood performance. In this work, the reservoir simulation model has been developed based on the geological model and available reservoir and fluid data. In particular, four high transmissibility strips were introduced to connect the injector-producer well pairs, simulating short-circuiting flow behavior that can be explained by viscous fingering and reproducing the water cut history. The strip transmissibilities were manually tuned to improve the history matching results during the waterflooding and polymer flooding periods, respectively. It has been found that higher strip transmissibilities match the sharp water cut increase very well in the waterflooding period. Then the strip transmissibilities need to be reduced with time to match the significant water cut reduction. The viscous fingering effect in the reservoir during waterflooding and the restoration of injection conformance during polymer flooding have been effectively represented. Based on the validated simulation model, numerical simulation tests have been conducted to investigate the oil recovery performance under different development strategies, with consideration for sensitivity to polymer parameter uncertainties. The oil recovery factor with polymer flooding can reach about 39% in 30 years, twice as much as forecasted with continued waterflooding. Besides, the updated reservoir model has been successfully employed to forecast polymer utilization, a valuable parameter to evaluate the pilot test’s economic efficiency. All the investigated development strategies indicate polymer utilization lower than 3.5 lbs/bbl in 30 years, which is economically attractive.
Enhanced Experimental Carbon Dioxide Sweep Using Surface Coated Silica Nanoparticles as a Foaming Agent
Authors: Alfakher Ahmad , DiCarlo David A.
Published: September 2021

Solvent flooding is a well-established method of enhanced oil recovery (EOR), with carbon dioxide (CO2) being the most-often used solvent. As CO2 is both less viscous and less dense than the fluids it displaces, the displacement suffers from poor sweep efficiency caused by an unfavorable mobility ratio and unfavorable gravity number. Creating in-situ CO2 foam improves the sweep efficiency of CO2 floods. Another application is the injection of CO2 foam into saline aquifers for carbon capture and storage (CCS).

The goal of the core flood experiments in this paper was to study the effectiveness of surface coated silica nanoparticles as an in-situ CO2 foaming agent. In each experiment, the pressure drop was measured across five separate sections in the core, as well as along the whole core. In addition, the saturation distribution in the core was calculated periodically using computed tomography (CT) scanning measurements. The experiments consisted of vertical core floods where liquid CO2 displaced brine from the top to the bottom of the core. A flood with surface coated silica nanoparticles suspended in the brine is performed in the same core and at the same conditions to a flood with no nanoparticles, and results from these floods are compared. In these experiments, breakthrough occurred 45% later with foamed CO2, and the final CO2 saturation was also 45% greater than with the unfoamed CO2.

The study shows how nanoparticles stabilize the CO2 front. The results provide quantitative information on, as well as a graphical representation of, the behavior of the CO2 foam front as it advances through the core. This data can be used to upscale the behavior observed and properties calculated from the core-scale to the reservoir-scale to improve field applications of CO2 flooding.
Premium Connections Fatigue Assessment Methodology Fit for Multi-stage Hydraulic Fracturing Operations
Authors: Zara Emanuel Mariano , Grittini Santiago Javier , Rodriguez Jordan Gonzalo , Perello Leandro , Sanders Mattew
Published: September 2021

Objectives/Scope

During casing installation and drilling operations, Oil Country Tubular Goods (OCTG) strings are often rotated inside deviated wellbores, generating cyclic bending loading that could lead to fatigue damage. This phenomenon has been previously studied and understood. The completion of multistage fractured horizontal wells (MFHW) involves tens of fracture operations (an ever growing number) as part of the stimulation program in order to maximize production. These fracture operations involve a combination of cyclic pressures and tension loading in the production casing, through which they are conducted, with maximum loads often repeatedly reaching the upper limit of the pipe body performance ratings. This process of cyclic pressure and tension loading near the upper limit of the pipe body performance is the subject of this work. In unconventional plays, where MFHW are the standard approach, both cyclic bending due to rotation and cyclic burst and tension due to multiple fracturing operations are applied on OCTG strings. This combination may lead to a failure mode in which a crack opens due to material fatigue during rotation or fracturing cycles, and subsequently propagates (to failure) during the demanding fracturing stages.

Methods, Procedures, Process

As it would be expected during any technological evolution, the industry has seen an increase in casing failures during hydraulic fracturing, often not explainable by the current understanding of loads scenarios present in wellbores. Some of these events could be associated to the failure mode described above. Despite the potential risk introduced by this failure mode, to date, there is no standardized testing methodology available to evaluate the resistance of pipes and connections to this loading sequence.

Results, Observations, Conclusions

In order to cover this gap, a testing sequence aimed at replicating actual operating conditions was developed and deployed by the authors. This includes evaluating the resistance of a premium connection to rotation through a curved hole, and subsequent burst and tension cycles. The methodology and results are presented in this paper.

Novel/Additive Information

Through this testing approach, operators, manufacturers, and laboratories alike, can ensure the performance and reliability of OCTG, which are key elements in the well construction process. As main observations, all tested specimens successfully passed this very demanding testing sequence, aimed to replicate operative conditions during installation and subsequent stimulation operation.
ARPR Assurance Standardization and Streamlining: A Digitalization and Automation Approach
Authors: Yaaribi Zainab , Hooti Huda , Al-Jumah Ali
Published: September 2021

This paper will discuss the improvement done to standardise the process of the Annual Review of Petroleum Reseources (ARPR) Process across PDO. How Digitalisation of the process saved time and reduced resources need to conduct such lengthy and complex exercise which done annually.

Many stakeholders are involved in the process, where applying standard digital solution "ARPR assurance tool' eliminated waste and accelerated progress, while following a Standard Operating Procedue (SOP).
Two-Phase Type-Curve Analysis of Flowback Data from Hydraulically Fractured Hydrocarbon Reservoirs
Authors: Zhang Fengyuan , Emami-Meybodi Hamid
Published: September 2021

This study presents a new type-curve method to characterize hydraulic fracture (HF) attributes and dynamics by analyzing two-phase flowback data from multi-fractured horizontal wells (MFHWs) in hydrocarbon reservoirs.The proposed method includes a semianalytical model, as well as a workflow to estimate HF properties (i.e., initial fracture pore-volume and fracture permeability) and HF closure dynamics (through iterating fracture compressibility and permeability modulus).The semianalytical model considers the coupled two-phase flow in the fracture and matrix system, the variable production rate at the well, as well as the pressure-dependent reservoir and fluid properties. By incorporating the contribution of fluid influx from matrix into the fracture effective compressibility, a new set of dimensionless groups is defined to obtain a dimensionless solution for type-curve analysis. The accuracy of the proposed method is tested using the synthetic data generated from six numerical simulation cases for shale gas and oil reservoirs. The numerical validation confirms the unique behavior of type curves during fracture boundary dominated flow and verifies the accuracy of the type-curve analysis in the characterization of fracture properties. For field application, the proposed method is applied to two MFHWs in Marcellus shale gas and Eagle Ford shale oil.The agreement of interpreted results between the proposed method and straight-line analysis not only demonstrates the practicality in field application but also illustrates the superiority of the type-curve method as an easy-to-use technique to analyze two-phase flowback data. The analysis results from both of the field examples reveal the consistency in the estimated fracture properties between the proposed method and long-term history matching.
Efficient Modeling of Proppant Transport During Three-Dimensional Hydraulic Fracture Propagation
Authors: Wang Jiacheng , Olson Jon
Published: September 2021

We propose an adaptive Eulerian-Lagrangian (E-L) proppant module and couple it with our simplified three-dimensional displacement discontinuity method (S3D DDM) hydraulic fracture model. The integrated model efficiently calculates proppant transport during three-dimensional (3D) hydraulic fracture propagation in multi-layer formations. The results demonstrate that hydraulic fracture height growth mitigates the form of proppant bed, so the proppant placement is more uniform in the hydraulic fracture under a smaller stress contrast. A higher fracturing fluid viscosity improves the suspension of proppant particles and generates a fracture larger in height and width but shorter in length. Lower proppant density and particle size reduce the proppant settling and create more uniform proppant placements, while they do not affect the hydraulic fracture geometry. Moreover, a larger proppant particle size limits the accessibility of the hydraulic fracture to the proppant, so the larger proppant particles do not fill the fracture tip and edge where the fracture width is small.