bluuebunny/crossref_metadata_2025_split huggingface dataset:
Fighting Water With Water: How Engineers are Turning the Tides on Frac Hits
Authors: Jacobs Trent 
Published: December 2018

Frac hits were once a painful cost of doing business for Abraxas Petroleum. But today, the San Antonio, Texas-based shale producer has softened the blows dealt by this widespread and challenging problem.
Its approach, called “active well defense,” has been put to the test amid the rolling hills of the company’s North Fork oil field in McKenzie, North Dakota.
“Necessity is the mother of invention—and that’s our story here,” said Peter Bommer, vice president of engineering at Abraxas, who noted that the driver of its strategy was not production declines, as it has been for others. Instead, active well defense is designed to prevent temporary, yet costly, production stoppages caused by unabated frac hits filling parent wells with sand.
The company starts by injecting produced water at low pressures into older, parent wells. It flows down miles of wellbore and into the formation’s partially depleted fracture networks where it has proven to prevent the damage often caused by high-pressure hydraulic fracturing of new child wells—known as frac hits.
Active well defense relies on sporadic injections to reinforce the preloaded water. To do this, Abraxas has partnered with a technology vendor Abra Controls, whose custom communications network gives engineers “real-time pressure monitoring so we can watch the wellhead pressures in the parents, and when we start to see interference, we start pushing back on it,” Bommer said.
Active well defense is now used across Abraxas’ infill program in its 3,300-acre development targeting the Bakken and Three Forks shale plays. Its genesis and evolution are covered in two technical papers, the latest of which was published at the start of the year (SPE 184851 and SPE 189860).
Renewed Trend
Examples of similar strategies have recently emerged from other major North American plays. They include BHP Billiton’s “preloads” in the Eagle Ford Shale of Texas and Canbriam Energy’s “pump-ins” in the Montney Shale of Alberta. Similar tactics are being tested in the Permian Basin and the Anadarko Basin.
This trend sits on one side of the well-defense spectrum, while on the other are the more capital-intensive projects known as cube developments that drill and complete a dozen or more wells in quick succession to avoid the downsides of reservoir depletion. Published results on injection-based well defense are encouraging, but it remains unclear whether they will scale up to stem concerns over the shale sector’s ability to sustain record output in the face of falling productivity of new child wells.
These operations are distinct from refracturing, as both Abraxas and BHP emphasize that the injections use pressures that do not open new fractures, or affect existing ones much.
Injection-based defense is not stopping frac hits, said Marcus Bayne, a fracturing supervisor with Abraxas. “But if we can interfere with the interference, then we can have the fluid we’re injecting act as a shock absorber, or a diffuser, so we don’t push solid material into the parent wellbore.”
Technology Focus: Water Management (December 2018)
Authors: Wilson Adam 
Published: December 2018

Technology Focus
“Water, water, everywhere, And all the boards did shrink; Water, water, everywhere, Nor any drop to drink.”—Samuel Taylor Coleridge, The Rime of the Ancient Mariner
Produced water has been an albatross around the neck of operators for a long time. It gets in the way of production by displacing the target oil, and it is filthy, requiring great expense to treat for reuse or disposal. Efforts to solve these challenges have been extensive and continue to evolve. These efforts can have a strong effect on the profitability of an operation.
The authors of paper SPE 187624 claim that the amount of produced water could be in the region of 210 million B/D for every 75 million bbl of oil produced. “Many oil companies could almost be called water companies,” they write. Their paper presents efforts to increase oil production while disposing of produced water by using an inverted electrical submersible pump. These efforts resulted in the disposal of water through the same wellbore, reducing the expense of bringing it to the surface for treatment and of drilling disposal wells.
Disposing of the produced water is only one factor that limits the profitability of operations. Treating the water before reuse or disposal also takes a substantial bite out of profits. Paper SPE 190272 examines an economical effort to desalinate produced water with the use of an electrochemical system with a resilient membrane. The membrane’s durability means that pretreatment of the water can be minimal, saving costs. In instances where polymer flooding is used, the membrane allows the polymer to remain in the desalinated water so that it can be used again. The cost savings from polymer reuse can be significant.
Production facilities also suffer from the massive quantities of water produced. When produced water moves with the stream through a facility, it takes up precious space that could be used more profitably by oil. Paper SPE 187109 takes a look at one of the ways operators are looking to ease this bottlenecking problem. By partially processing the stream to remove water at the production manifold, more room is made for oil through transfer piping and in primary separation and floating storage facilities. The authors claim this has increased oil production by 80% and reduced the in-field transfer volume by 62%.
For more solutions to the persistent problems of produced water, please see the papers listed as recommended additional reading and find more in the OnePetro online library (www.onepetro.org).
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 187119 Employing Effective Water Treatment in West Texas To Mitigate Surface-Equipment Failures by Sarkis Kakadjian, Keane Group, et al.
SPE 190129 Case Studies of an Effective Methodology To Collect Formation Water To Meet Regulatory Requirements for Formation-Water Sampling by V.H. Tran, Chevron, et al.
SPE 188400 Successful Field Application of Bulk Water Removal Debottlenecks Declining Songkhla Marginal Offshore Fields, Extending Economic Life by Manuel De La Sota, CEPSA
Improvement and Learnings from Reservoir Performance Analysis in a Large Scale Thermal Pilot in North Kuwait
Authors: AlAbbasi Lulwa , AlMatrook Mohammad , AlRubah Abdullah , Rawnsley-bettembourg Solenn 
Published: December 2018

Abstract
A Large Scale Thermal Pilot (LSTP) has been in operation in Northern Kuwait in a Heavy Oil Field for some time. Currently, the pilot wells are on Steam flood (SF), after completing two cycles of Cyclic Steam Stimulation (CSS). This paper presents the analysis that led to the improvement of reservoir performance, and the critical learnings from monitoring the steam chamber development from different well completions.
The LSTP in the North area of the field consists of 26 vertical production/injection wells, distributed into eight inverted 5-spot patterns. One is a 10-acre area pattern targeting one reservoir unit and the other one is a 5-acre pattern area targeting two commingled reservoir units.
A systematic approach for data integration was used by multiple disciplines to improve the thermal recovery of the pilots. This integrated approach led to gaining thermal recovery field experience and learnings for improvement of future commercial development thermal operations in the subject heavy oil field.
This paper presents the pilot performance improvements, learnings, and new challenges after analysis of the reservoir performance, including production and injection data, valuable information from dedicated observation wells, impact of completion designs for free-gas and sand management, and supporting systems such as water disposal and water source.
Successful pilot performance improvement under the thermal application was promising and it will support the commercial full-scale phase development by implementing the learnings and the integrated approach of all teams, from surface to subsurface, with a shared goal.
Evaluation of Well Completions in the First Steam Flood Pilot Performed in an Unconsolidated Sandstone Reservoir in Kuwait
Authors: Pandey Dharmesh Chandra , Al Shammari Nayef Fadhel , Al-Dhafeeri Aiydah Khaled , Al-Naqi Ahmad , Al- Arfan Faisal , Gonzalez Santiago , Diri Muhammad 
Published: December 2018

Abstract
A steam flood pilot in unconsolidated sandstone reservoir is being performed for the first time in Kuwait with inverted 5 spot configuration and pattern areas of 5 and 10 acres and a total of 26 wells. Prior to the steam flood, two cyclic steam stimulation (CSS) cycles were applied in all wells. This paper provides a detailed description of the well completions and challenges during CSS and the ongoing steam flood operations.
Different designs of well completions were evaluated for injection and production wells. Injection well completion designs were evaluated by comparing actual vs. expected injection rates and review of operational issues. Production well completion designs were evaluated by comparing peak production rates, decline rates and sand issues.
Two different injection well completion designs were evaluated. In the 5 acre, the steam injectors target two sand sub layers and hence initially completion were designed with downhole steam splitters but later removed due to injectivity issues. In the 10 acre, steam injectors target a single sand layer using packer less completions. Production wells were completed with 7" case hole perforated with 3.5" completion tubulars and insert sucker rod pump (ISRP). Sand screens were installed in some producers, but 50% of them were removed later due to very sharp production declines. When the screens were pulled out, screens were found completely plugged with debris.
The responses from the 2 CSS cycles were very good with average peak well production rates of higher than 100 BOPD. The steam flood pilots have been running for around 6 months and the preliminary results are very encouraging. There is a clear initial response to steam flood, characterized by an overall increase in gross and oil production.
The experience and the lessons learned from the CSS and evaluation of initial response of steam flood pilots are very useful in risk identification and mitigation applicable to the commercial phase.
Seismic Quantitative Interpretation of Heavy oil Reservoir Characterization in North Kuwait
Authors: Ren Zu Biao , Al-Rabah Abdullah A-Karim , Albloushi Ahmad , Freeman Michael Edward 
Published: December 2018

Abstract
Key challenges to seismic imaging of shallow heavy oil recovery in North Kuwait include how to acquire high quality seismic data, and how to carry out seismic inversion and quantitative interpretation (QI) for reservoir characterization. Kuwait Oil Company acquired a high resolution baseline 3D seismic survey over an area of 700m × 700m in January 2017, followed by a six week time-lapse 4D seismic survey, as part of geophysical monitoring project for studying the reservoir and associated steam flood pilot performance. This paper presents the technical methodology and interpretation results of these 3D and 4D seismic surveys.
Highly pressurized and heated steam injected into a reservoir will move in all directions to drive out in situ heavy oil. It is important to understand where the steam has traveled to, which is controlled by reservoir properties such as formation pressure, porosity, and permeability. Seismic inversion and quantitative Interpretation (QI) are proven tools that can extract information about reservoir properties such as sand probability and porosity, which can be used to estimate steam chamber size, optimize the steam injection strategies and update the geological static modeling.
The 3D and 4D seismic inversions have confirmed that the data quality meets the QI requirement for such a shallow reservoir. The main outcomes from the pre and post stack inversions are the sand porosity and sand probability. Due to steam injection in the reservoir, seismic amplitude anomalies and time-shifts were observed from seismic slices and time-delay processing, which could be used for estimation of steam injection size. Sand porosity and probability maps were created of the upper zone overlying the lower steamed reservoir, and clearly indicate that steam from the lower reservoir passed through the intervening baffle and spread to the upper zone, which means that the thin baffle in this area could not prevent steam from traveling upwards.
The key enabler for proper seismic quantitative interpretation is the rock physical modeling, which searches and establishes the relationship between reservoir properties (i.e. sand probability and porosity) and seismic attributes such as P-Impedance and Poisson's Ratio (Vp/Vs). Inputs into the rock modeling process include bulk density logs, compressional and shear sonic logs, and interpreted porosity and clay volume petrophysical logs. A sand probability function is first established using P-impedance and Poisson's Ratio, and then reservoir properties are extracted from the seismic inversion.
Geochemical Modeling to Evaluate the Performance of Polymer Flooding in a Highly Sour Sandstone Heavy Oil Reservoir
Authors: Al-Murayri Mohammed Taha , Kamal Dawood Sulaiman , Garcia Jose Gregorio , Delshad Mojdeh , Britton Christopher , Fortenberry Robert 
Published: December 2018

Abstract
The Umm Niqa Lower Fars (Heavy Oil Field) oil reservoir has very favorable properties of high permeability, low temperature, and moderate oil viscosity for polymer flooding and work is progressing towards implementing a polymer pilot in this target reservoir. Nonetheless, Heavy Oil Field contains high salinity water, it is shallow with concerns about injectivity limitations, and high concentrations of H2S (up to 5 mol% in reservoir fluids) which may adversely impact the effectiveness of the injected polymer solutions. A comprehensive laboratory and numerical modeling was initiated to address some of these issues. One potential concern is the degradation of polymer in the co-presence of H2S and possible oxygen introduced with polymer solution injection. This study is aimed at evaluating the impact of H2S on polymer performance in the Heavy Oil Field reservoir via geochemical simulations based on laboratory data.
Previously performed polymer rheology and transport experiments were history matched and model parameters were developed for subsequent simulations. Transport behavior of both HPAM type and biopolymers was modeled incorporating two new features of viscous fingering and filtration models.
This was then followed by a geochemical simulation study to assess and potentially de-risk the presence of H2S near the wellbore assuming that all oxygen in the injection water (if any) is rapidly consumed by reservoir rock minerals and oil.
The parameters developed for the rheology of the polymers were very robust and represented the effects of salinity and polymer shear thinning over a wide range of polymer concentrations for each polymer. These parameters were then used to conduct simulation studies on waterflooding and polymer flooding in the presence of near wellbore H2S. Sensitivity simulations to relative permeability/wettability, oil viscosity, polymer concentration were also conducted to identify the impact on injectivity of polymer solution. The use of the newly added viscous fingering and filtration models was necessary in some cases to correctly model the transport behavior of unstable displacements. Geochemical evaluation showed that injecting H2S-free water over a period of ~3 months can significantly reduce H2S concentration in the near-wellbore region (~30 ft) due to stripping from the oil phase. This is advantageous for the injected polymer because even if small oxygen concentration is co-injected with the water, there would be no H2S present to cause polymer degradation.
This study presents a practical approach to de-risk the deployment of polymer flooding in a highly sour shallow sandstone heavy oil reservoir. The findings of this study will be evaluated in a one-spot EOR pilot soon.
Methodology to Improve Techno-Economic Viability of Surfactant-Flooding in a Shallow Sandstone Heavy Oil Reservoir
Authors: Al-Murayri Mohammed Taha , Hassan Abrahim Abdelgadir , Al-Ajmi Naser Ammash , Wartenberg Nicolas , Delbos Aline , Suzanne Guillaume 
Published: December 2018

Abstract
There are ongoing efforts to assess the techno-ecnomic viability of surfactant polymer (SP) flooding to increase oil recovery by improving microscopic and macroscopic sweep efficiency. This paper sheds light on a methodology to design an appropriate SP formulation for potential deployment in the Ratqa Lower Fars (RQLF) heavy oil reservoir in Kuwait.
Besides achieving low residual oil saturation due to SP flooding under typical RQLF reservoir conditions, this study focuses on mitigating surfactant retention. Several injection strategies were investigated using alkali, adsorption inhibitors and a variety of water treatment techniques. For each scenario, a specific SP formulation was designed and evaluated through static adsorption tests using crushed reservoir rock. The two most promising options were then evaluated through coreflood experiments. The best option was selected based on in-depth chemical propagation, oil desaturation and surfactant adsorption. Finally, lab-optimization work was performed through additional corefloods to reduce chemical consumption while maintaining favorable oil recovery.
Softened seawater obtained through reverse osmosis was considered as the most appropriate water source to implement the desired SP process. Previous work revealed that the use of unsoftened seawater results in high levels of surfactant adsorption on reservoir rock. Salt addition allows applying an efficient salinity gradient post SP injection. Sodium chloride was used instead of alkali which did not exhibit any benefit in this case. A particular effort was made to reduce the amount of added salt and the corresponding formulation cost. Several injection sequences were investigated to compare polymer and SP flooding. The final coreflood experiment based on SP injection (0.6 PV of surfactant at 4 g/l), followed by a salinity gradient, and involving a polymer drive recovered 80% of the original oil in place. The promising performance of this injection sequence will be further evaluated using the results from a one-spot EOR pilot.
This EOR study on the RQLF shallow heavy oil reservoir in Kuwait provides important insights to select an appropriate surfactant-polymer injection strategy to increase oil recovery while maintaining reduced adsorption levels, thereby improving SP techno-economic viability.
Heavy Oil Enhancement Process for Deep Heavy Oil Reservoir in Kuwait Field
Authors: Mohammed Noor , AL-Rashidi Hamad , Safar Abdul-Aziz , Duncan Bruce , AL-Sagheer Asmaa , Muhsain Batoul 
Published: December 2018

Abstract
Kuwait is in the process of developing the deeper heavier oil reservoirs as part of Kuwait's national oil production strategy and KPC strategy 2040. This is in order to increase the oil production capacity for the next decade. The enhanced recovery of heavy oil assets needs a high level of expertise, optimum technologies and techniques, which are tailored to the distinctive challenges of the reservoirs and performed in a cost effective manner to optimize output and maximize economic benefits and rate of returns.
Several wells are perforated in the zones of interest of the reservoir within the study area, which is currently under production using Progressing Cavity Pumps and is under natural production phase. The low productivity oil producers are completed in the Burgan reservoir. This reservoir is characterized by very high viscous crude oil around 15,000 cp, with a low gas-oil ratio (10-30) and with little or no primary drive mechanisms. The project requires overcoming certain challenges the following challenges are identified as the key challenges:
Limited fluid mobility which is due to the high viscosity of the oil. Absence of drive support associated with the dissolved gas, the depth of the well, and the oil and its compositional gradient reservoir. Non-thermal well completion of the well, and the perforation design policy that was implemented. Lack of fluid/rock characterization and being in an oil-wet system.
In the design of this project, the suggested method to be used is a non-thermal optimization process "chemical treatment ". The chemical treatment will be implemented as the chosen technology for a well that ceased producing in 2009. This method which has been applied globally and has also been proven to have less impact on the environment as per KOC HSE policy. The selected environmentally friendly method has three important mechanisms, which are as follows:
Acts as a Wettability alteration agent. Acts as a Viscosity reducer agent. Acts as an Asphaltene inhibitor agent.
KOC successfully conducted a pilot in 2016 and after the well was put back on to the production phase an increase of 300 bbl/day (net oil) was attained. The return of investment (ROI) of this pilot was a key economic calculation in answering the economic benefits of this procedure and in validating the project. As well showing the economic benefits of the projects value and its impact on the margin. The return of investment (ROI) was captured within day of production, with the total profit for the first 34 days was 438,885.52 USD.
Design Optimization of Slotted Liner Completions in Cased and Perforated Wells: A Numerical Skin Model
Authors: Velayati Arian , Roostaei Morteza , Fattahpour Vahidoddin , Mahmoudi Mahdi , Nouri Alireza , Alkouh Ahmad , Fermaniuk Brent , Kyanpour Mohammad 
Published: December 2018

Abstract
Several parameters affect the skin factor of the cased and perforated (C&P) wells completed with slotted liners. Existing skin factor models for slotted liners account for such factors as the flow convergence, pressure drop and partial production but neglect phenomena such as partial plugging of the screen or near-wellbore permeability alterations during the production. This paper discusses these factors and incorporates them into a skin model using a finite volume simulation.
The finite volume analysis evaluates the skin factor as a result of pressure drop in the gap between the casing wall and the slotted liner. This skin model accounts for: 1) the perforation density and phasing, 2) slotted liner specifications, and 3) different amount of sand accumulation in the annular space between the casing and the sand screen. A semi-analytical pressure drop model is also linked to the numerical model to incorporate the skin factor due to flow convergence behind the perforations.
The results of finite volume analysis reveal that a low perforation density would behave close to the open-hole completion for sand-free casing-liner annular space. Conversely, pressure drops were found to be significant for a partially or totally filled space. Additionally, it was found that the optimum completion design occurs if the slotted liner joints are in line with the casing joints. Besides, a partially perforated casing or a partially open sand screen increases the distance fluids have to travel in the annular space and intensifies the skin factor.
This paper provides skin models derived for vertical and perforated wells completed with slotted liner sand screens using the finite volume simulations. Each part of the model has been verified against existing numerical models in the literature. The model improves the understanding of flow performance of the sand screens and skin factor, which in turn leads to a better design of sand control completions.