bluuebunny/crossref_metadata_2025 huggingface dataset:
Technology Focus: Drilling Innovation (February 2020)
Authors: Weatherl Michael H.
Published: February 2020

Technology Focus

Summer jobs working on drilling rigs in western Oklahoma and California in 1980 and ’81 were great adventures. High oil and gas demand meant major and independent operators used some of the latest, state-of-the-art rigs to probe deep into high-pressure reservoirs. Planning and executing wells back then was a manual process with experience, horsepower, pencil, and calculator. My adventures continued after I graduated from college in 1982. Ever-evolving drilling, completion, and subsurface technology characterized the years that followed.

Fast forward to February 2020. “The more things change, the more they stay the same,” the old-timers might say. In many field locations today, old-school machinery and processes remain in place. However, we see artificial intelligence (AI), data analytics, machine learning, and related advancements transforming our industry. These developments have been headlines for several years now but will take more time to reach full fruition. Experts agree this is just the beginning. Jensen Huang, chief executive officer and founder of Nvidia, highlighted this during a CNBC interview in November. “We are at the beginning of the AI revolution, one of the most powerful technological forces of all time,” he said. “We’ve created the ability for computers to understand the code of human knowledge. All industries will be transformed.” Huang, an AI visionary, showed a 4D simulation of an unmanned Mars landing craft on final approach going from 12,000 mph to zero in 6 minutes. Such visionaries are also working in upstream exploration and production to achieve remarkable advancements.

A focus on drilling innovation reveals no shortage of SPE papers that exemplify these exciting trends. Without exception, the featured articles reflect increased volumes of surface and downhole data that are being captured and analyzed to enable deep learning, improved efficiency, safety, and value. As noted in paper OTC 29487, oil and gas companies are creating layers of digital knowledge enabling a new generation of AI-driven applications. New insights into mitigation of drillstring vibration, well-control events, and rate-of-penetration optimization follow. Managed-pressure drilling remains a persistent trend that continues to evolve across onshore, offshore, and geographical boundaries, opening new frontiers once seen as out of reach. One need not look to outer space to imagine the extent of breakthroughs to come in the not-too-distant future.

Recommended additional reading at OnePetro: www.onepetro.org.

SPE/IADC 194535 Nitrogen-Cap Drilling: A Managed-Pressure-Drilling Alternative for Highly Fractured Carbonate Reservoirs by Alexey Podust, Tengizchevroil, et al.

SPE 196166 Standardization: Successful Implementation of Driving Consistency in Deepwater Operations by Daniel A. Durey, Shell, et al.

SPE 197942 Innovative Digital Well-Construction-Planning Solution Enhances Coherency and Efficiency of the Drilling-Design Process by Waldemar Szemat-Vielma, Schlumberger, et al.
Emulsified Polymer Gel Pickering Emulsion for Conformance Control: Emulsion Formulation, Stability and Coreflooding Investigation
Authors: Saikia Tinku , Sultan Abdullah , Barri Assad , Shamsan Abdulmalek
Published: February 2020

The water production from the oil wells not only increases the per barrel oil production cost but also raises environmental concerns. The use of conventional water shut-off techniques not only restricts the production of water but also reduces the oil production. The use of emulsified polymer gel system presents an efficient way for conformance control in the oil reservoirs. The emulsified polymer gel system was designed in such a way that it will separated into oleic and aqueous phase encountering higher reservoir temperature. The aqueous phase will become gel and provides the resistance towards the water flow whereas the oil phase will provide the passage to oil, towards the production well. In this research work, an emulsified polymer gel system was developed having polyacrylamide and polyethylenimine as aqueous phase and diesel as oleic phase. The organoclay Cloisite 20A was used as an emulsifier. The emulsified polymer gel system was characterized by dilution test, microscopic analysis and gel strength code. The developed emulsified polymer gel was found to be water-in-oil emulsion system, which formed rigid gel (gel strength grade-I) under reservoir temperature conditions. The thermal stability of the emulsion system was tested at 105°C. The emulsion stability index of the emulsified gel system was also calculated. To check the effectiveness of the developed emulsified gel system for conformance control, core-flooding experiment was performed at 105 °C. During the core flooding experiment, the system provides desired resistance to water flow whereas allow the diesel oil to produce with ease. This indicates that the developed emulsified polymer gel system is an effective conformance control system, which can be used in high temperature reservoirs. This research work presents a core flooding experiment study, to evaluate the performance of emulsified gel system (Pickering emulsion) for conformance control in high temperature reservoirs.
Challenges and Potentials for Sand Control Design and Management in Oil Reservoirs of Kazakhstan
Authors: Soroush Mohammad , Hosseini Seyed Abolhassan , Roostaei Morteza , Pourafshary Peyman , Mahmoudi Mahdi , Ghalambor Ali , Fattahpour Vahidoddin
Published: February 2020

Kazakhstan owns one of the largest global oil reserves (~3%). This paper aims at investigating the challenges and potentials for production from weakly-consolidated and unconsolidated oil sandstone reserves in Kazakhstan.

We used the published information in the literature, especially those including comparative studies between Kazakhstan and North America. Weakly consolidated and unconsolidated oil reserves, in Kazakhstan, were studied in terms of the depth, pay-zone thickness, viscosity, particle size distribution, clay content, porosity, permeability, gas cap, bottom water, mineralogy, solution gas, oil saturation, and homogeneity of the pay zone. The previous and current experiences in developing these reserves were outlined. The stress condition was also discussed. Furthermore, geological condition, including the existing structures, layers and formations were addressed for different reserves.

Weakly consolidated heavy oil reserves in shallow depths (less than 500 m) with oil viscosity around 500 cP and thin pay zones (less than 10 m) have been successfully produced using cold methods, however, thicker zones could be produced using thermal options. Sand management is the main challenge in cold operations, while sand control is the main challenge in thermal operations. Tectonic history is more critical in comparison to the similar cases in North America. The complicated tectonic history, necessitates the geomechanical models to strategize the sand control especially in cased and perforated completion. These models are usually avoided in North America due to the less problematic conditions. Further investigation has shown that Inflow Control Devices (ICDs) could be utilized to limit the water breakthrough, as water coning is a common problem, which initiates and intensifies the sanding.

This paper provides a review on challenges and potentials for sand control and sand management in heavy oil reserves of Kazakhstan, which could be used as a guideline for service companies and operators. This paper could be also used as an initial step for further investigations regarding the sand control and sand management in Kazakhstan.
Prevention of Core Jamming and Damage During Coring Operations by Optimization of Drilling Parameters – Analysis of Case Studies
Authors: Ashena Rahman , Lotfi Mosayeb , Nascimento Andreas , Ghalambor Ali
Published: February 2020

Coring is a considerably costly drilling operation, but vital to retrieve valuable sources of ground-truth data in the oil and gas industry. To justify the high cost of this operation, essentially, cores should not undergo jamming and mechanical damage. Core jamming not only indicates an unprecedented termination of the operation, but also causes severe damage to the core column already taken in the barrel. This means that the cores cannot be retrieved with sufficient key performance indicators (KPIs); thus, it would not reliably represent reservoir properties. Reaching this significant target can be ensured not only by proper design, but also by online monitoring and investigation of the drilling parameters. This investigation predicated on several case studies in the Middle East to identify the effect of imperfect decisions made by the driller. Based on the experience and observations, the paper provides practical recommendations to alleviate the impact of such negative actions.

The drilling parameters observed in the mud logging data of six coring case studies (of several runs from three wells in carbonate reservoirs) were investigated at the depth interval just prior to jamming occurrence. These parameters consist of rate of penetration (ROP), torque, weight on the bit (WOB), rotary speed (revolutions per minute, RPM), circulation rate, and standpipe pressure (SPP). In this work, a main cause of the core jamming occurrences is discussed; that is, the improper drilling parameters application, as mismanaged by the driller. Finally, as indications of jamming, sudden variations of the drilling parameters at the specified depth were investigated. Such study can contributeto the better monitoring for future coring operations.

Based on the observations in six case studies in three wells, WOB was identified as the most significant reason causing core jamming; that is, jamming occurred when the WOB was not steadily maintained on the bit probably due to the driller’s inexperience, shift change, etc. For monitoring, torque decrease, ROP decrease, and SPP variation or decrease (following initial increases) were identified as indications of core jamming. Torque showed to be a significant parameter forjamming detection when it decreases or its trend becomes completely straight, i.e., without any variations, indicating that the core head may not be in contact with the formation. Next, drilling issues during coring (such as pump failure) can contribute to subsequent jamming.

The case studies in this paper provide several observations and indications of core jamming occurrences in a limestone reservoir which can be attributed to non-optimized drilling parameters. The paper also provides several practical recommendations and measures to prevent core jamming and core damage.
Filter Cake Breaker Evaluation for Water Injectors: Scale Up From Laboratory to Field Deployment
Authors: Chandran Pavithiran , Kumar Arunesh , Cameron Iain , Jackson Phillip , Twynam Allan , Reid Rachael , Sweeney Kieran
Published: February 2020

Water injection wells were planned to provide pressure support to oil producers in two North Sea fields (Field A and Field B). For both fields, water-based drilling fluid was selected to drill the reservoir section. The average permeability of the first field is 1000 mD and the second field is 50-100 mD. A laboratory study was commissioned to evaluate and optimize filter cake breaker systems for use in water injectors to efficiently remove external and internal filter cake in order to attain matrix injection without the need for backflow to clean up the sand face.

A time-delayed filter cake breaker system was chosen for evaluation as part of the study. Laboratory-scale formation damage tests indicated significant loss of injectivity, potentially due to deep invasion of xanthan polymers in core plugs along with incomplete dissolution of calcium carbonate from the filter cake. An enzyme package designed to degrade xanthan was included in the revised breaker solution and an improvement in injectivity was recorded. Further adjustments were made to the breaker formulation to optimize performance for density range, corrosion mitigation and dissolution of calcium carbonate, including allowance for the impact of the addition of lubricant to the drilling fluid.

Following an extensive and detailed study, a much greater understanding of the design, evaluation and field engineering aspects of chemical breakers has been gained. The recommendations from the study have recently been applied to injection wells on both fields.

This paper describes the test procedures adopted for evaluating the various filter cake breaker formulations and the work conducted to develop the systems to be ready for field use. The challenge and consequences around scaling up laboratory results to field conditions is particularly acknowledged. Field results are presented, highlighting both the importance of critical design issues and applied learnings for a successful outcome.
Analysis of Time Lapse Formation Damage Evolution Throughout the Life of a Well
Authors: Bellabiod Sofiane , Deghmoum Abdelhakim , Madani Habib Yssaad , Karacali Ozgur , Shumakov Yakov
Published: February 2020

Formation damage can significantly defer hydrocarbon production. Formation damage is one of the key parameters to evaluate the quality of various operations during the life of a well. The evolution of formation damage over the long run is rarely studied. This paper will present a new model of time dependent skin factor measurement. Multiple field examples are analyzed and modelled comparatively to evaluate the magnitude of the time-lapse formation damage for specific reservoir rocks.

Several mathematical models have been developed to model formation damage mechanisms. However, it is cumbersome to isolate and individually compute the contributing mechanisms of actual damage. Formation damage is a combined effect of the pore size distribution, fines migration, fluid compatibility problems, wettability, presence of inorganic salts deposition, insufficient well clean up, organic substance deposition, multiphase flow effects, etc. The proposed innovative approach utilizes the skin factor in pressure transient analysis to measure the time-lapse evolution of formation damage. The methodology has been applied to various reservoir rocks to quantify the impact for a specific rock type.

This paper will present an innovative technique and methodology to quantify the formation damage that has been materialized during the life of a well, from drilling to production. A robust technique to quantify the total damage is the computation of the skin factor from pressure transient tests conducted at various times. Observations confirm that there is a mathematical relation between the formation damage, type of drilling and completion fluid, formation rock type, and exposure time. Pressure transient tests conducted after drilling, casing, and perforating were analyzed. These initial pressure transient test results were compared with production tests performed years after drilling. Various field examples from North African reservoir rocks are presented to depict the applicability of the time-lapse method to quantify the formation damage for a given specific reservoir rock. Remedial stimulation work has been performed in such damaged wells. Formation damage could be removed, and the productivity has been revamped. The stimulation procedure has been based on core plug tests of various stimulation fluids. Potential stimulation strategies to remove or minimize formation damage are also discussed in this paper.

In this paper a new methodology and mathematical relation have been described to quantify the time-lapse formation damage mechanisms. Field examples from North African reservoirs have been depicted. The findings could be easily utilized to apply the time-lapse methodology for similar reservoir rocks in other parts of the globe to measure and quantify the magnitude of the formation damage.
Visualization of Flowback Aid Mechanisms Utilizing a Microfluidic Pore-Scale Device
Authors: Ren Ginger , Abedini Ali , Yang Hyuntae , Sanders Aaron
Published: February 2020

Using flowback additives in slickwater fracturing fluids is a relatively recent innovation, and regained permeability testing using corefloods is the preferred performance evaluation method. The coreflood rig simulates the hydraulic fracturing process by injecting the fracturing fluid through a core under relevant pressure and temperature conditions, and measures the permeability and relative permeability changes during injection. Permeability measurements indicate whether the fracturing fluid damages the formation during hydraulic fracturing that in turn reduces oil productivity during flowback. While coreflooding is useful for comparing the performance of different flowback aids, it is unable to resolve the mechanisms associated with porescale transport. The goal of this study is to directly visualize and quantify the pore-scale dynamics of fracturing fluid injection and oil flowback using a microfluidic chip device and correlate these observations to the coreflood test results. Microfluidics-based measurements provide pore-scale visual evidence of the flowback dynamics, not achievable using conventional experimental methods such as the coreflood.
Successful Wellbore Cleanup Using Environmentally Friendly Chemicals to Enhance Well Productivity
Authors: Sharma Hemant K , AlKhalifah Qasim , Al-Mulhim Abdulrahman K. , Al-Shammari Mubarak J.
Published: February 2020

Drilling long horizontal and multilateral wells in the oil industry helps lower the drawdown, and minimize water or gas coning, which enhances well productivity. Many of these wells are drilled using drill-in fluid (DIF), which is cleaner than conventional mud and so is considered to be less damaging to the formation. The DIF consists of polymers for building the required viscosity to transport cuttings and deposit a filter cake around the wellbore to reduce fluid loss. Most DIFs are composed of starch, cellulose or Xanthan polymers added with bridging agents of calcium carbonates and salt particles.

Even though DIF causes less formation damage than conventional mud, damage to target formations can still occur. To remove formation damage caused by DIF, a new chemical technology is tested. The new chemical technology, which breaks up the coherence and integrity of the mudcake and polymer gel, was used for wellbore cleanup with very encouraging results. In addition, the chemical is also an eco-friendly, noncorrosive bio-enzyme and is naturally biodegradable. The chemical disintegrates into its natural elements (carbon, hydrogen, oxygen and nitrogen) after converting the insoluble polymers into water soluble sugars. In addition, the chemical minimizes formation of wormholes like in acid, which helps in keeping the wellbore away from getting connected to fractures/fissures.

This paper highlights the technological advantage of using the enzyme based chemical and how homogenous wellbore cleanup/stimulation is achieved, leading to productivity enhancement and sustainable oil production.
Test Results Field & Lab for a New Composite Perforating Method that Integrates Propellant and Shaped Charges
Authors: Albert Larry
Published: February 2020

A new perforating technique employing the integration of conventional shaped charges and solid propellant was described by Albert, et.al. (SPE 197185-MS). The innovative propellant deployment method allows the propellant deflagration to occur in the perforation tunnel rather than gun body and casing, thus delivering maximum energy to improve perforation tunnel performance. Shaped charges utilizing high energy explosives perforate casing and formation with high speed metallic jets that displace by sheer force. The explosive events are fast (20-30 microseconds) high impact events (as high as 1.5 million psi at the rock face) that can collapse large pores in the formation along the surface of the perforation tunnel. This crushing along the tunnel reduces permeability and increases skin and can impact the flow of fluids into and out of the reservoir rock. A number of methods have been developed to improve perforation tunnel flow efficiency, but all suffered limits on either deployment or effectiveness.

Propellants have been used for decades to improve perforation performance. Propellants are energetic materials with slower burn rates that can micro-fracture the formation and break-up the crushed zone around perforation tunnels. Prior methods deflagrated the propellant materials within the gun bodies, or casing and lost a significant amount of energy before delivering impact to the perforation tunnel. The new method with a composite cap of solid propellant on the face of the shaped charge, displaces the propellant into the perforation tunnel before deflagration, thus delivering maximum energy to the formation. This helps break up the crushed zone and micro-fracture the formation.

The improved perforation tunnel will reduce frac fluid tortuosity. Frac jobs can get better fracture initiation and better proppant placement, resulting in better production. This paper will focus on additional lab testing at an Advanced Perforating Flow Laboratory plus several USA onshore completions (horizontal and vertical). The field data will show the effect of the composite perforation method on frac performance and well production.
Retarding HCl Acid Reactivity Without Gelling Agents, Emulsifiers, or Polymers for Low to High Temperature Acidizing Applications
Authors: Reyes Enrique , Beuterbaugh Aaron , Ashcraft Paul , Pires Renata , Althoff Heloisa
Published: February 2020

Placement of highly reactive stimulation fluid based on hydrochloric acid (HCl) into high temperature reservoirs or long pay intervals can be challenging and requires proper techniques to limit near-wellbore (NWB) spending, deconsolidation, and to extend the depth of fluid penetration. This is important when long laterals or interval characteristics limit injection rates away from the optimum, causing inefficient use of stimulation fluid. HCl acid, although readily accessible and widely used, can be highly problematic for far-field placement and stimulation.

The addition of a low viscosity and nonpolymeric, fully water soluble surface modifying agent into 15 to 28% HCl acid formulations generates a fluid with a very distinct interaction on a carbonate-laden matrix, facilitating the control of premature spending in the NWB area. Core flow studies using Indiana limestone (IL) demonstrated that this surface-binding agent results in minimal core face erosion and spending, a minimization of pore volume to breakthrough (PVbt), and overall improved fluid efficiency. The fluid formulations tested and corresponding results confirm them to be effective over a broad range of temperature from 150 to 300°F, porosity from 8 to 20%, permeability from 0.2 to 800 mD, and flow regimes from 0.5 to 100 mL/min, thus highlighting the flexibility and ease of use.

For all tests using the low viscosity HCl acid formulation, PVbt volumes were reduced in comparison to plain HCl acid, whereas the most notable volume reduction occurred when nonoptimal flow regimes were used. At flow rates of 1 mL/min, the formulated HCl acid fluid provides more than a five-fold PVbt reduction under similar conditions. More importantly, core face dissolution, characterized by computed tomography (CT) imaging, demonstrates that rock integrity is maintained even under extreme conditions, such as extremely low flow rate injection or temperature in excess of 300°F. On the contrary, even core flow tests performed at optimal flow rates provide a half-PVbt reduction when compared to plain HCl acid. The low viscosity HCl acid formulation has exhibited improved results across a breadth of downhole conditions that signify greater penetration and stimulation of carbonate reservoirs. Fluid compatibility with several necessary or expected HCl acid additives or stabilizers has been conducted and thoroughly tested, and such results indicate complete efficacy. Using the nonpolymeric surface agent in HCl acid fluid can provide a benefit in terms of equipment use and can facilitate stimulation treatments when pumping or completion limitations dictate low injection rates.

Helping prevent inefficient and undesired spending allows the reactive fluid to penetrate deeper into the formation, accessing more reservoir area and providing larger drainage of the stimulated reservoir while helping prevent formation damage under high temperature or low injection rates.
Successful Application Analysis of Double Water Control in Fractured Reef Reservoir in Liuhua Oilfield
Authors: Luo Donghong , Dai Zong , Wang Yahui , Pei Bailin , Wang Hailong , Shen Zheng , Zhu Hongxia
Published: February 2020

Water breakthrough (WBT) in the horizontal wells often leads to water flooding in the well, especially to those heavy oil reservoirs in reef limestone carbonate. The excessive water production from the hydrocarbon producing horizontal wells can adversely affect the economic life of the well, furthermore this could result in the well permanent abandonment. Nowadays, no effective methods of water control are available for the similar reservoirs, traditional water control methods have three technology barriers: (1) can not accurately locate the WBT positions;(2) difficulty of identifying the wellbore completion, fluid, and nearby formation conditions;(3) Not being designed to control water from new water breakthrough points.

This paper shows a newly developed water control technology by using continuous Packed-off double water control technology (CPI). It was successfully implemented in a well of a fractured reef limestone oil field in South China Sea. This technology completely overcome the above shortcomings of traditional water control methods. The mechanism is to pack patent particles into the wellbore and near-wellbore fractures to create a double "artificial well wall". It suppresses radial and axial turbulence effectively. The operation procedure of CPI water control method is simple. It has been proven with lower cost and longer effective duration of controlling water, which can greatly increase oil recovery.

Results show that the water content in the well of CPI water control is only 10% to 33% of the adjacent wells at the same geological layers. The initial oil water ratio in the CPI well is 13, which is ten times better than the adjacent wells. After 2 months' production, the water content of CPI well is 13.3%, compared to 67%, 62%, and 89% of the adjacent wells.
Digital Oilfield: Review of Real-time Data-flow Architecture for Upstream Oil and Gas Rigs
Authors: Sletcha Ben , Vivas Cesar , K. Saleh Fatemeh , Ghalambor Ali , Salehi Saeed
Published: February 2020

Advances in horizontal drilling and completion techniques have proliferated onshore development of unconventional shale fields. These wells can span hundreds of miles across a field for a single operator. Live remote monitoring and automation of operations is ideal but rarely cost-effective.

Upstream oil and gas operations face many challenges measuring and sending data from remote well sites. Sensors must operate in remote areas, challenging terrain, and inhospitable environments, making very difficult to implement a wireless data flow collection and transmission. Additionally, data integration and consolidation between many devices, software packages, file sizes, and file types, compounds the challenges for analyzing the data for potential improvements in operational efficiencies.

Autonomous remote measurement, transmission, and control of oilfield sensors continuously pursued, but rarely fully implemented. The fast production decline of unconventional shales makes high-cost telemetry systems perceived as not economic to install within a few years after the initial production of a well. However, Oil and Gas industry sensors are improving in reliability and become more robust to work in harsh environments. The transmission networks have increased their capabilities and coverage, representing the evolution of every component that conforms the onshore oilfield data architecture, becoming their implementation easier than the recent past.

This paper describes the real-time data-flow architecture for oil and gas well operations, and what are the main challenges of implementing the digital oilfield concept by studying the actual use of devices in the field and the conditions in which they operate for understanding the digital oilfield implementation challenges. Also, there are presented some examples of how the industry is benefiting from real-time data-flow architecture and a brief introduction of how it can be connected with big data implementation for enhancing oilfield operations.
A Novel Approach to Salvaging Well Completions with Mud Damage using a Specialized Fluid System; The First Cases in Nigeria
Authors: Ogbunuju Emi , Okolomma Emmanuel , Ibrahim Yahaya , Imbazi Onyeintonbra , Ukpe Uduak , Burts Donnie , Justus Charlie
Published: February 2020

Well re-entry necessary to wash/cleanup suspected barites and barium sulfate residues in two wells located onshore Niger Delta, Wells AA & BB drilled and completed to develop a cumulative of over 700 Bscf of gas and 30MMstb of associated condensate reserves at an initial cumulative potential of 240 MMscf/d, producing below par at about 15% planned daily production.

The sand face for these Single String Gas Producers were drilled with 13.8ppg POBM. Post well completion, hookup and initial cleanup, the wells were suspected to have remained suspended with drilling and completion debris also, various HUD's were encountered within completion string.

Previous reentries proved rather unsuccessful for the operator as these wells could not be cleaned up even after using 3 different traditional stimulation fluids pumped in high volumes. As a result of the challenges experienced during the previous interventions, the operator sought a different approach which included the deployment of a specialized stimulation treatment, which is a mixture of organic acids, solvents and clay inhibitors with built in corrosion sequestration and de-emulsifiers via CT.

This specialized two-fluid treatment comprising of pre-flush and main treatment was sequentially pumped and allowed to soak for 5hrs and 36hrs respectively.

CT run planned to be performed with a jetting tool run across the SAS was not feasible as there was no access to the bottom of the SAS assembly as several attempts to mill out the HUD encountered in the tubing string proved abortive.

This paper aims at presenting advances in barite dissolving capability with non-damaging stimulation fluid and powerful "descaler" which although reacts quicker in warm environments (>100°F), is not largely temperature dependent to reach depletion with normal reactions taking place within 24hours. The post stimulation results and recovered debris validates the dissolving capabilities for cleaning sulphates of barium, strontium and calcium as well as calcite in wellbores.
Formation Damage Control, Modeling, Analysis and Remediation Techniques
Authors: Al-Qasim Abdulaziz , Almudairis Fahad
Published: February 2020

Formation damage can occur in the vicinity of the wellbore or far field in the reservoir. Organic and inorganic deposition such as asphaltene, paraffin, iron sulfide, barium sulfate and calcium carbonate are the most commonly encountered scale types of damage. Accidental interactions between the completion kill fluid after the perforation or the drilling fluid while drilling through the target zone are also major causes. The decline of well productivity is the first indication of formation damage and can be used as a determining factor of its severity. Therefore, the type of damage, the mechanisms, and controls need to be analyzed and predicted.

This paper presents a detailed and comprehensive review of formation damage including both the external and internal types and the far field and near-wellbore damage. Damage can be identified by observing changes mainly in the well productivity; however, it can be also observed using retrieved equipment such as logging tools and downhole pumps or due to the restricted entry of completion equipment such as inflow control devices (ICDs). The impact of well configuration on the formation damage and the remedy afterwards is also discussed in details.

The present study provides a solution and control criteria for the formation damage and a comprehensive mechanistic modeling is proposed. The model is applied by coupling reservoir modeling with the wellbore conservation equations through the pressure. The effect of horizontal laterals is included by developing three-phase transient equations to account for the flow rate change from toe to heel in the drain hole.
Gas Production Enhancement by Polymer Treatment
Authors: Zaitoun Alain , Templier Arnaud , Hernando Louis
Published: February 2020

Many gas wells in Adriatic Sea are suffering from both water and sand production. An original sand control polymer technology has been successfully implemented and has proven to be an efficient way to stop sand production and thus maintain gas well under steady production. In many wells, a reduction of water production was observed as side effect. Nevertheless, the main objective remained sand control and not water control.

The present paper describes a polymer treatment performed in an offshore well equipped with sand control gravel-pack downhole completion. This well was suffering of high level of water production inducing a severe decline in gas production. The preparation of the treatment consisted of lab coreflood tests aiming at checking the behavior of the selected polymer (P-321) in actual reservoir conditions. The product was shown to have good injectivity and to strongly adsorb on the reservoir rock. Moreover, it has good RPM properties, inducing a strong reduction in water relative permeability while preserving gas relative permeability.

The treatment proceeded in the bullhead mode, i.e. through the gravel pack. The polymer was followed by a Nitrogen postflush to squeeze the product deep in the formation and help restarting the well. Immediately after treatment, gas rate increased while water rate levelled off. Both gas rate and GWR (Gas Water Ratio) stopped declining and remained at same level for two years. After two years, the estimated additional gas production was 13,330 KSCM and the well keeps flowing steadily instead to be probably shut in if it had followed its initial decline trend.
Reinforcement of Polyacrylamide-Co-Tert-Butyl Acrylate Base Gel Using Nanosilica for Conformance Control at Low and High Reservoir Temperatures
Authors: Shamlooh Mohamed , Hamza Ahmed , A. Hussein Ibnelwaleed , S. Nasser Mustafa , Salehi Saeed
Published: February 2020

Challenges of water shut-off, which is categorized under conformance control, are nowadays common in the oil and gas industry. The excessive water quantities produced from oil reservoirs can make the production process economically infeasible. The target of water shut-off process is plugging fractures or high permeability zones to decrease water cuts. Polyacrylamide tert-butyle Acrylate (PAtBA) is used for such applications. Silica (silicon dioxide) has been found to have a strengthening effect as well as it enhances the thermal and mechanical stability of the system. The objective of this study is to introduce nanosilica to reinforce PAtBA crosslinked by polyethyleneimine (PEI) and chromium Acetate (CrAc3) for low and high temperature conformance control applications. In this study, different ratios of polymer to crosslinker were investigated to choose the optimum combination. Then, nanosilica (NS) with different sizes (20, 50 and 85 nm) was added to the polymeric formulation with the inorganic crosslinker (CrAc3) to study the effect of silica content and size on gel strength. While, the reinforcement of the organically crosslinked gels with PEI was accomplished at 130°C. Evaluation of different systems was based on testing the rheological behavior of the mature gel based on the final storage modulus (G′). Differential scanning calorimeter (DSC) technique was also employed to understand the nature of chemical interaction between the various chemicals. The investigation reveals that PatBA:CrAc3 of 9:0.5 is the optimum ratio producing the most strong gel. Silica with the size of 20 nm has produced the strongest gel by increasing the storage modulus by more than 150 %. At high temperature (130°C), 50 nm silica with PAtBA/PEI showed the highest storage modules compared to other sizes. DSC investigation discloses that silica is an inert and has no effect on the gelation reactions. Thus, silica has physical interactions with the polymer in the form of hydrogen bonding which enhances the strength of the gel in comparison with silica-free gels. Therefore, this study introduces a new polymeric formulation that serves as a water shut-off agent for reservoirs at low and high temperatures. The formulation that consists of PAtBA, CrAc3 and NS makes the system more stable and gives it more resistivity toward high shears. Whereas higher gel strength was achieved when PAtBA/PEI/NS was used at high temperatures.
First Open Hole Gravel Pack with AICD in Ultra Deep Water
Authors: Pedroso Carlos Alberto , Latini Carolina , Araujo Zaque , Garcia Peterson , Soares Robson
Published: February 2020

The execution of Open Hole Horizontal Gravel Packs (OHHGP) in ultra-deep waters (greater than 1500m) demands the use of the best technologies available. For the Atlanta Project, a detailed description of the first two wells successfully completed with OHHGP in the field, was provided in previous papers (OTC-25813, SPE-174893, SPE-174896). The third Atlanta well faced a new challenge: the integration of AICD technology (Autonomous Inflow Control Device) in the gravel pack screens.

Due to the restriction imposed to the flow through the screens by the AICDs, the resulting pumping pressure and associated ECD (Equivalent Circulating Density) is increased, further reducing the already narrow operational window, which is common for reservoirs in such water depths. The use of AICD technology, which imposes an additional pressure drop to the aqueous fluid flow, further increases the pumping pressure, making conventional gravel packing strategies and procedures unfeasible.

To overcome these new challenges, dozens of simulations were performed to address the new challenge and an innovative screen configuration was adopted to facilitate effective gravel pack placement while retaining the necessary fluid flow restriction of the AICD operating as per the simulation design during well production. Additionally, to ensure effective and complete gravel pack efficiency, a new pumping procedure, incorporating the use of three different proppant strategies, was implemented.

By introducing these innovations, the third Atlanta well was 100% packed and the expected PI was obtained. Long-term performance, with the aid of tracers installed in the screens, is being evaluated.

This paper will detail all the planning and execution phases that enabled completion of the first open hole gravel pack with AWES RP T2 AICDs in ultra-deep waters. Also in this paper, the production evaluation data is analyzed.
Using Particle Size Theories to Optimize Bridging Solids for Post-Gravel-Pack Screens
Authors: Abiodun S. , Vincent J. M. , Schultz K. , Rapp E.
Published: February 2020

A simple and effective particle-size selection program was developed to significantly reduce the amount of testing required when designing bridging solids systems for use in fluid loss control pills for gravel-pack or frac-pack applications. Applying Ideal Packing Theory (also known as the D½ rule) and Abram's 1/3 rule with some modifications, linear plots of cumulative volume percentage of bridging particles versus the square-root of particle diameter was used to obtain optimal formulations of bridging solids in ratios that effectively bridged and sealed machined, laboratory-grade, wire-wrapped screens of 2.5-inch. o.d., 2-inch i.d., and 0.25-inch thickness.

High-pressure/high-temperature (HP/HT) filtration testing of optimized screen-specific formulations of calcium bromide-based TETRA SmartSeal™ pills was completed using 6, 8, 10 and 12 gauge screens under 500 psi pressure and 215°F temperature conditions over a 72-hour period.

The results show that low-permeability, well-packed filter cakes of thickness less than 2 mm were formed on the screens, allowing minimal fluid passage, with average spurt volume less than 6 mL, average 30-minute filtrate volume less than 8 mL, and maximum 72-hour filtrate volume less than 25 mL.
Our Choice: study protocol for a randomized controlled trial for optimal implementation of psoriasis treatment by the integration of Chinese and Western Medicine
Authors: Sun Xiaoying , Zhou Xiaoyong , Wei Yuegang , Yang Wenxin , Huang Ning , Ding Yangfeng , Hu Rongyi , Guo Shun , Yang Chunyan , Weng Huilan , Zhang Ying , Chen Xi , Ding Xiaojie , Liu Liu , Yin Qingfeng , Wang Ruiping , Li Xin , Li Bin
Published: February 2020

Background: Plaque psoriasis is a refractory inflammatory skin disease. The common therapies used to treat plaque psoriasis in traditional Chinese medicine (TCM) and Western medicine (WM) therapies have distinct characteristics and advantages. Although a combination of TCM and WM therapies, adjusted to the clinical situation, is widely used; there are no systematic studies on the hierarchical selection of this treatment combination, based on the severity of skin lesions. We therefore designed a randomized clinical trial to focus on the sequence of internal and external treatments of TCM in patients with mild to moderate plaque psoriasis and to optimize the integration of Chinese and Western medicine for the treatment of patients with severe plaque psoriasis, thereby achieving high-level clinical evidence and establish treatment norms for the integrated use of Chinese and Western medicines. Methods: In this proposed multi-center, single-blinded, randomized, controlled trial, 108 patients, with mild-to-moderate plaque psoriasis, will be randomly assigned to two groups in a 1:1 ratio to receive either internal or external TCM treatment and 270 patients, with severe plaque psoriasis, will be randomly assigned to three groups in a 1:1:1 ratio to receive treatment with TCM or WM, or TCM+WM. All enrolled patients will receive 8 weeks of treatment. Follow-up assessments will be done 8 weeks after the treatment. The primary outcome of this study is the evaluation of efficacy and relapse rate, based on the psoriasis area and severity index, and the secondary outcome measures include determination of the affected body surface area, physician’s global assessment, pruritus scores (determined using a visual analogue scale), TCM symptom score, dermatology life quality index, patient-reported quality of life score, and incidence of serious adverse events. Discussion: This study will provide a high-level clinical evidence for internal and external TCM treatment optimization and will contribute to establishing norms for the integration of Chinese and Western Medicines.
Intention to quit water pipe smoking among Iranian women: A qualitative directed content analysis
Authors: sabzmakan leila , Eslami Fatemeh , Sighaldeh Shirin Shahbazi , Izuka Nkeonye Judith
Published: February 2020

Background: Water-pipe smoking is the most common type of tobacco used among Iranian women. The aim of this study was to explain women’s perceptions of their intention for quitting water-pipe smoking based on the theory of planned behavior.Methods: The study was a qualitative content analysis which was carried out over four months in 2016 in Tehran-Iran. The participants were 26 women ages 18 to 45-years-old who smoked water-pipe and were selected through snowball sampling. The study was performed in hookah cafes, parks, and homes. The data were collected through individual interviews. The interviews were open-ended questions based on the theory of planned behavior. Directed content analysis was used to analyze the data. Results: Findings showed that the women did not intend to quit water-pipe in that time. Main contributing factors influencing not having intention of cessation were positive attitude and false beliefs toward hookah smoking, as well as having peers and family members who smoked WP or approved its use. Although most females realized the obstacles associated with hookah cessation, they believed that quitting WP smoking was up to themselves and could control more barriers.Conclusion: Social pressure, positive attitude and false beliefs towards hookah smoking, as well as external and internal obstacles diminished women ‘s intention for cessation. Therefore, it is recommended to apply the theory of planned behavior into behavior change interventions in order to increase the intention to quit water-pipe smoking.
Quality of Life in chronic musculoskeletal symptomatic Chilean population: Secondary analysis of National Health Survey 2009-2010
Authors: Mena-Iturriaga Maria Jesus , Mauri-Stecca Manuel Vicente , Sizer Phillip S. , Leppe Jaime
Published: February 2020

Background: Health-related quality of life (HRQoL) is defined as the patient's perception of their health status. HRQoL can be modified by illnesses, treatments or social and health policies. Chronic musculoskeletal pain is a modifying factor of HRQoL that leads to lower quality of life, elevated suffering and disability. Knowing HRQoL in subjects reporting chronic musculoskeletal symptoms (cMSS), like pain, discomfort or swollenness lasting more than 3 months, will provide information to health teams and organizations engaged in the Chilean health system. This study aim was to determine the relationship between HRQoL and musculoskeletal symptoms measured in three different Chilean groups: (1) without symptoms; (2) with acute symptoms; and (3) with cMSS. Methods: A secondary analysis of the 2009-10 Chilean National Health Survey (NHS) was executed to determine the relationship between HRQoL (measured with SF-12) in three MSS groups. The Chilean NHS considered a national, probabilistic, stratified and multistage sample of 5,293 participants aged 15 and older; it was representative at the national, urban-rural and regional levels. A multivariate logistic regression model studied the relationship between cMSS and HRQoL, adjusted for age, sex, educational level and residence area as control variables (p<0.05). Results: Out of 5,293 participants in the NHS 2009-10, 5,276 subjects were included for analysis. The median age was 46 years (IQR 31-60), 59.4% women, a median of 10 years formal education (IQR 7-12) and an urban residence in 85.2% of the population of the NHS 2009-10. The observed population prevalence of people with cMSS was 42.6% (95% CI 40.4 - 44.9). Presence of cMSS is a risk factor for low HRQoL, exhibited both in the physical (OR 3.1 95% CI 2.7-3.5) and mental (OR 1.9 95% CI 1.6-2,) HRQoL dimensions, independent of control variables. Conclusions: Physical and mental HRQoL are affected in people with cMSS, low educational level and advanced age. This is especially seen in women. This information will facilitate assessment and treatment of cMSS as a prevalent and multidimensional health problem.