bluuebunny/crossref_metadata_2025 huggingface dataset:
Novel Approach in Digital Diagnostic for Plunger Lift in Unconventional Wells at Vaca Muerta
Authors: Barros J. L. , Claramunt J. I. , Ferrigno E..
Published: October 2018

This paper presents studies performed to optimize the operation of the artificial lifting system, Plunger Lift, in wells producing unconventional oil in the Vaca Muerta Formation, Unconventional Region, YPF S.A., Argentina.

The field has more than 280 wells equipped with Plunger Lift. Most of them are instrumented, and automated, telesupervised.

Despite the level of technology deployed, both in the field and in SCADA systems, the dedication of specialized production engineers was necessary to study the wells on a daily basis and in real time, implementing exception handling, in order to detect early warnings and assess opportunities for optimization.

On the basis of experience in the operation and optimization of this extraction system and the work of multidisciplinary teams, diagnostic and decision making flowcharts were elaborated and then considered as early warning algorithms in SCADA control panels. This paper presents the results of these studies and the benefits obtained.
Plunger-Assisted Gas Lift and Gas-Assisted Plunger Lift
Authors: Burns Maggy
Published: October 2018

Plungerlift was installed in conjunction with gaslift to improve efficiency in delifiquification of unconventional gas wells. The dual artificial lift methods were implemented to more aggressively reduce bottom-hole pressure, in order to increase production in Barnett Shale wells.

Wells are selected based on a series of metrics, including gas-liquid ratio, fluid production, casing pressure and differential between casing and line pressure. The basics of both plunger-assisted gaslift (PAGL) and gas-assisted plungerlift (GAPL) both utilize injection gas and a plunger to optimize the well. Plunger-assisted gaslift is continuous injection and continuous plungerlift. PAGL is implemented on higher gas and fluid producers. These wells require the addition of injection gas to raise the critical velocity needed to lift both the plunger and the fluid of the well. GAPL is intermittent injection and conventional plungerlift. It is implemented on lower gas and fluid producers. Gas is only injected during certain phases of the plunger cycle to supplement the wellbore inflow and successfully lift fluid and plunger to surface.

This presentation will describe the process and results of installing PAGL and GAPL on specific case studies in the Barnett Shale. Historical data, including production, pressures and producing methods will be presented, to compare the results of prior lift methods to those of PAGL or GAPL. By implementing PAGL and GAPL, bottom-hole pressure was successfully lowered and production increased. A secondary benefit is the reduced quantity of gaslift that results in lower operating costs and a more-effective use of horsepower. The results of over-injection in unconventional wells will also be notated.

This presentation will detail the benefits and results of dual artificial lift that can efficiently and economically add value to a field.
Challenging Sand Producer Well Handling with PCP in Eastern Desert, Egypt
Authors: Alsawi Kamel , Hegazy Mahmoud , Elhady Khaled , Sayed Mahmoud
Published: October 2018

Objectives/Scope

Kuwait energy company has started to develop oil reserves since 2008 in AREA-A Concession, started with production of 2,000 BOPD increased to 7,300 BOPD in 2017, and due to presence of depleted and shallow wells in YUSR Field "main producing field" in the concession, sand production troubles started to increase, and one of the challenging wells "YUSR-38" which was re-completed on Rudis-1B reservoir via beam pumping system; but unfortunately the well failed three times due to plunger sticking in barrel and caused some complicated fishing operations due to sever sand production; however increased the plunger clearance to -0.007 and used sand screen with the pump, tried to restore the well production via running the well with PCP but unfortunately sand fall down above the pump and lead to stuck again.

Therefore, initiated a challenging objective to restore the well production and to get learned from the previous well failures via running well designed PCP to handle the sand production and to handle the maximum well productivity matching the current reservoir depletion

Methods, Procedures, Process

Four ways were considered for maximizing the well productivity and to handle the excessive sand production, firstly perform sand clean out job till reach bottom of the hole and ensure rat hole is well cleaned due to limited volume of rat hole "6 Mt. inside 5″ casing", secondly Performed sand sieve analysis and determined the particle size of sand and calculated sand settling velocity, and hence took a decision to reduce the utilized tubing size from 3 ½″ to 2 7/8″ to increase fluid and sand velocity to overcome expected sand settling velocity, thirdly; increasing pump speed to overcome the expected sand settling velocity and utilized PCP size 15-1800 to match well depletion due to utilizing higher PCP speed, that is in addition pumping brine water from casing side to match PCP productivity due to increasing PCP speed to overcome sand settling velocity, and finally utilized slotted tag bar with PCP installation to avoid plugging pump intake with sand due to limited volume of rat hole

Results, Observations, Conclusions

The well productivity was restored and the well is currently producing 100 BOPD with current life time exceeds 3 months and still working; while in the previous installations the life time didn't exceed two weeks, and production didn't exceed 60 BOPD.

Novel/Additive Information

The well productivity was restored and the well is currently producing 100 BOPD with current life time exceeds 3 months and still working; while in the previous installations the life time didn't exceed two weeks, and production didn't exceed 60 BOPD.
Impact of Gas Lift Design in Unconventional Wells - A Delaware Basin Operator's Perspective
Authors: Kannan Subash K , Boyer Matthew , Dufresne Jeff , Gonzalez Luis E.
Published: October 2018

Gas lift is becoming a predominant, intermediate term, artificial lift system in the Delaware and other basins. Besides the proper selection and management of the gas lift systems, design methodology is still a challenge due to the drastic change in flow conditions in the transient phase. The main objective of this paper is to develop a new methodology to design and optimize gas lift wells in unconventional reservoirs. A case study is provided to review, model, and analyze the current design over different stages of the well's production life. Consequently, application of new designs over different stages of the well's life will be implemented using a performance comparison which includes production and unloading scenarios. Actual well data will be used along with steady-state and dynamic modeling for unloading and production performance estimation. The models will be evaluated using actual data to perform history matching over different stages of the well's production life. This evaluation will also answer the following questions: Is the use of conventional mandrels the best option for these types of wells? Are the number of mandrels deployed using the traditional design methodology the correct solution? Are the tools used to design and analyze these types of wells sufficient? Most importantly, is more data required to create a better design and analysis? Also, this study compares the existing design to modified designs and justifies how the later could perform better. Integration of all data sources including historical performance, flowing bottom hole pressure, inferred dynamic IPR data, and the use of dynamic and nodal analysis tools for modeling while varying production conditions and unloading scenarios.
Innovative Downhole Design for Optimizing ALS Installation at Shale Oil Wells
Authors: Cuneo I.. , Ardito J. M. , Rivero G. Garcia
Published: October 2018

The aim of this paper is to show how tubing (TBG) installation has evolved, with the problems and learning processes experienced along the brief history of exploitation of the Vaca Muerta formation in the Loma Campana field.

The production behavior of wells from Vaca Muerta consists initially of flows close to 100m3/d, with sufficient pressure to produce natural flowing by the 5" casing, controlled by an orifice at wellhead.

Once the flowing period finishes, the well starts using mechanical pumping to keep producing with this system in the long term. Wells with a higher gas oil rate (GOR) are converted to plunger lift before resorting to mechanical pumping.

Due to the fact that a well experiences different extraction stages in a relatively short period of time (flowing by casing - flowing by TBG - Plunger Lift - mechanical pumping), it is necessary to find an installation that is flexible enough to allow switching from one stage to the other with the least amount of slickline and pulling interventions.

Likewise, the installation should be able to minimize the effects of sand and gas existing in Vaca Muerta, which affect the performance of mechanical pumping.

Thus, this paper shows how TBG installations have changed to finally reach the current installation. This installation allows the conversion of a flowing by TGB installation into a mechanical pumping installation with gas buster, poor boy type, using slickline intervention and pump and rod running, thus avoiding the necessity of moving the TBG.
Getting Wells Back to Production Using an Innovative Artificial Lift System for Recovering Inactive Wells
Authors: Vargas A. F. , Duran J.. , Simpson A.. , Santos R.. , Doval J. M. , Muñoz L.. , Patino Jerez A. E. , Rativa C.. , Hernandez N.. , Rozo Rozo , Rios D..
Published: October 2018

This paper presents a successful application and the lessons learned during a pilot test under which a new electrical submersible pumping technology was installed in 4 wells. These helico-axial downhole pumps, V-Pump, were installed under a program of new technologies testing, which aimed for artificial lift run life extension in an extremely high sand-producing field under current cost constraints.

The oil price turndown forced Casabe Field to leave some wells inactive, even though they still have significant reserves. The cause of this decision was the expenses associated to the high frequency of interventions required due to the adverse sand production effects on the artificial lift systems.

Due to the low run life of conventional artificial lift systems that are customary to use in the field, it was necessary to search for emerging technologies that would meet the challenge presented. A screening process for new technologies were conducted, and after that, these pumps were installed in four wells, which were continuously monitored with downhole temperature, vibration and pressure sensors, fluid levels measurement, VSD readings and production tests, which would allow to understand the technology performance to achieve the desired run life, oil production gain, and to obtain lessons learned to design the second phase of the testing project.

The use of this innovative pumping technology extended the run life in the pilot wells between 180% and 420%, allowing the production of their remaining oil reserves, and giving a new approach in the production strategy of the field. One well is still running after 13 months.

Also, based on the on the information collected during the well production phase, through downhole sensors and VSD parameters, and the findings during the pump's dismantle, some recommendations were made to improve the performance in the second phase of the project. Recommendations include both improvements in the pump design and to the screening process of candidate wells.
Development of Low Toxicity and High Temperature Polymer Drilling Fluid for Environmentally Sensitive Offshore Drilling
Authors: Liu Xiaodong , Xie Binqiang , Gao Yonghui , Gu Huiling , Ma Yongle , Zhang Yong , Zhang Ruxin , Li Qingyang
Published: October 2018

It brings severe challenges to drilling fluids when drilling high temperature deep well in environmentally sensitive sea area and facing strict environmental protection laws and regulation requirements meanwhile, the toxic value of drilling fluid must reach up the standard requirement of 30,000 mg/L.A new, environmentally safe water-based polymer system has been developed for drilling applications with temperatures resistance to 200°C and biological toxicity value LC50 more than 100,000 mg/L.

The new system consists of two basic polymeric components for high temperature rheology and filtration control, along with a special nano-plugging agent, glycol shale inhibitor, extreme pressure lubricant, and barite or formate weight material, providing superior performance for a variety of drilling environments. The system shows the base slurry is light colored and non-toxic to the marine environment, which can be discharged directly into the sea. The environmental friendly feature is a significant superiority over traditional high-temperature systems, such as sulfonated drilling fluid and oil-based drilling fluid which normally require the use of a large number of poisonous additives.

Experiments show that the new system has three important characteristics. Firstly, thermal stability time is more than 72h when aging at 200°C, HTHP filtrate loss is in the range of 12 to 25mL between temperature of 150 and 200°C, and sodium chloride and calcium chloride pollution resistance reach up to 200,000ppm and 5,000ppm, respectively. Secondly, the characteristic of excellent lubricity and inhibition can be comparable to oil based drilling fluids. Thirdly, the low biological toxicity also is one the most important characteristic, 96h LC50 semi lethal concentration of artemia is more than 100,000 mg/L, and EC50 median effective concentration of luminescent bacteria is more than 300,000 mg/L, which meet the biological toxicity discharge requirements for the first level sea area.

The extensive testing results of this new drilling fluid demonstrated its superiority characteristic and low biological toxicity to marine environment. Good results from field testing in Bohai offshore oil field are also presented, the deepest test well depth is 6066m, and the highest downhole temperature is 204°C.
Well Control for Offshore High-Pressure/High-Temperature Highly Deviated Gas Wells Drilling: How to Determine the Kick Tolerance?
Authors: Chen Xuyue , Yang Jin , Gao Deli , Huang Yi , Li Yanjun , Luo Ming , Li Wentuo
Published: October 2018

Kick tolerance is a vital parameter for well control. It indicates if a shut-in operation can be performed or not, an appropriate method of well killing should be selected. However, the kick tolerance determination for offshore high-pressure/high-temperature (HP/HT) highly deviated gas wells drilling still remains as a challenge to the oil and gas industry due to the presence of narrow safe mud weight window of the HP/HT well section, complex borehole temperature profile, influx distribution and high frictional pressure loss. In this work, a model of volume kick tolerance specific for offshore HP/HT highly deviated gas wells drilling was presented based on the pressure bearing capacity of highly deviated open hole, casing shoe, casing, blowout preventer (BOP) and choke valve. Meanwhile factors affecting the volume kick tolerance were also investigated. The result shows that both of the volume kick tolerance for shut-in and the volume kick tolerance of well killing increase with wellbore inclination of the highly deviated section, and the highly deviated wellbore or highly deviated wellbore may have a much higher volume kick tolerance than that in vertical wellbore. With other parameters values setting constant in this case, the volume kick tolerance of well killing increases with the geothermal gradient while the increase rate is not obvious. This work provides a practical tool for enhancing well control in offshore HP/HT highly deviated gas wells drilling.
First-Time Implementation of Water Management Technology to Improve Water Flooding Performance in a Multi-Restriction Injector Well: Brownfield Redevelopment, Onshore Thailand
Authors: Thawatthukool Prasen , Toempromraj Wararit , Lilaprathuang Pipat , Kaewwetchawong Chasin , Weeramethachai Deephrom , Kiatrabile Thanita , Krisadasima Supakorn , Wattanasuwankorn Reawat , Daohmareeyor Tuanangkoon , Kangsadarn Arweephan , Kritsanaphak Kritsana , Pathmanathan Indran
Published: October 2018

An operator recently launched a "water-shutoff" polymer development project for an onshore injector well in a brownfield operation in Thailand. To effectively improve water flooding performance in this field, shutting off a water thief zone was a prerequisite.

Several conservative expanding tubing pads placed in the upper zones restricted access to the lower zone perforations or placement of another tubing pad in the lower zones; therefore, operational planning and strict laboratory testing were performed. This included setting-time testing using an actual chemical blend in batch mode, which closely simulated bottomhole conditions. The process required shutting off the upper zone to facilitate water injection into the lower zone, employing coiled tubing (CT). The design consisted of a shut-off treatment with a lost-circulation material (LCM) to help ensure wellbore fluid placement and shutoff in the high-permeability water thief zone at the designated positions, and to ensure that the pressure response could be monitored from the surface.

The shut-off operation was performed as planned, and CT was used for cleanup after placement. Water-production monitoring has shown that the shut-off polymer is one of the best solutions for this field in terms of safety, economics, and operation. As a result of well testing, after the thief zone shut-off treatment, water injectivitywas decreased by approximately 97%, demonstrating the effectiveness of the technique in terms of safety, economics, and operation. A long-term monitoring program was established to evaluate the polymer’s seal-off performance for development of future field strategies. Such an operation could help increase oil recovery by 5 to 10% of oil in place.

This technique does not require mechanically sealing off the perforations, making it more feasible for future well interventions and enabling a greater injection rate for chemical EOR where desired.
Application of Temporary-Blocking Fracturing Technology in Casing-Deformed Shale Gas Well
Authors: Naizhen Liu , Ming Liu
Published: October 2018

In the past five years, as one of the most active country for the shale gas development all over the world, China has been experiencing a boom of shale gas development. In 2017, the total yearly production of shale gas has reached about 350 BCF in China. As the planning goes on, the yearly production will reach 1000 BCF in 2020. The market is huge regardless that the task is difficult.

There are four national shale gas demonstration plots in China, CW plot, JSB plot, ZT plot and YA plot. JSB plot is the first to obtain breakthrough for the shale gas development, contributing the half of the total yearly production of shale gas in China. CW plot is the second successful plot, which contributes about 30%. This paper will describe the casing deformation which is the knottiest problem not only CW plot but for all plots.

The casing deformation of shale gas wells in China happens frequently, which restricts the gas production to a great extent. This paper describes the application of temporary-blocking fracturing technology in a casing-deformed shale gas well to minimize the loss. In this well, only one stage of hydraulic fracturing is conducted leaving 19 stages (about 1400m) untreated due to the casing deformation. First of all, the wiper trips are made to confirm the deformation point is around the drilling target spot A, and the maximum drift diameter decreases from 114mm to 83mm. Since there is no smaller bridge plug, then the temporary-blocking fracturing techonology is determined to be conducted. 16 stages are designed for the 1400m interval. For feasibility, the 16 stages are separated into 8 rounds of fracturing. A total of 7756 blocking balls and 2750kg blocking agent are used to block the perforations for the 16 stages. To enlarge the stimulated reservoir volume (SRV), the volume of fracturing fluid and the quality of proppant injected for one stage are designed as 53Mcf and 120t respectively. The treatment pressure indicates that the pumped blocking agent is effective. From putting the well on production, the average daily production is 3.53MMcfd which is no less than that of wells without casing deformation in the same pad. Based on the chemical analysis of the collected flowback fluids, the blocking agent is 100% dissolved and has no damage to the formation. The application of this technology successfully solves the problem of casing deformation so as to reduce the production and economic loss.
A Precise MPD Technology to Reduce Risk in Drilling of Fractured Cavernous Carbonate with Narrow Pressure Margins
Authors: Chen Peng , Zhou Yingcao , Liu Wei , Wang Junjie
Published: October 2018

It is effective to drill horizontal wells in carbonate to increase production. However, the horizontal sections were limited and hard to be extended by means of conventional drilling due to high risk of drilling in fractured cavernous carbonate. Application of a precisely pressure controlled drilling system was developed to have successfully drilled and extended horizontal sections, reduced risk of drilling in the said kind of wells with narrow pressure margins in western China’s Tarim basin.

A comprehensive MPD technology with 9-operational situations, 4-controlling modes and 13-precise controlling techniques of emergent changeovers was built up through full-size laboratory test, field test and deployment. Under-, near-, or over-balanced MPD was selected and carried out to meet diversified requirements based on proper well trajectory design, build-up rate control, retention of margin for adjustment and control of the well track, dynamic prediction of bottomhole pressure alternation while drilling according to the stability of the formation and whether toxic gases existed.

Drilling in Tarim basin usually experienced complex geology, narrow density margin, low ROP, frequent downhole complex and accidents, and long drilling duration. After the precise MPD technology being applied in Tarim basin, the risk of kick-and-loss coexistence has been reduced and the well cost has been gained beneficial results. The application assisted not only the hydrocarbon discovery of reef flat geology of Ordovician system in China’s Tarim basin, but also the well deliverability enhancement, effective treatment of downhole complex, and improvement of ROP. Application of precise MPD in a Tarim horizontal well created a record for deepest horizontal well with MD at 8,008m, TVD at 6,327m, and horizontal section of 1,551m. Another Tarim horizontal well produced a new record of daily footage 150m and horizontal footage 1,561m, and 42 pay zones were discovered. The difficulty of horizontal section pressure control in fractured cavernous carbonate was effectively resolved and multi combinations of fractures and caves were drilled through by application of precise MPD technology. The horizontal sections, historically limited by 200m-300m, were largely extended in fractured cavernous carbonate horizontal wells, and the well capacities were advanced.

Drilling of fractured cavernous carbonate horizontal wells is an integration and innovation of the precise MPD technology, downhole risk control, and the optimization and control of horizontal well trajectory. The precise MPD technology could effectively avoid or alleviate downhole risk, cut non-productive time, extend horizontal section, promote rate of penetration, reduce drilling cycle, achieve safe drilling, and therefore reduce well cost. It would play a significant role in future challengeable drilling activities.
Geosteering in a Complex Deepwater Reservoir in the Niger Delta
Authors: Ndokwu C. , Foekema N. , Okowi V. , Olagundoye O. , Umoren N. , Delpeint A. , Ndefo O. , Agbejule A. , Jeje O.
Published: October 2018

Geological and geophysical uncertainties account for most of the challenges encountered during the placement or geosteering of high-angle and horizontal wells in deepwater environments. Structural uncertainties could result from the targeted subsurface structure that is folded, undulating and faulted. Lateral discontinuity of sand bodies, lateral variations in sand thickness, multiple beds, and formation heterogeneities are some of the more common sedimentological uncertainties. Geophysical uncertainties include the vertical depth of the seismic data and seismic reservoir characterization. These uncertainties make increasing the likelihood of success during geosteering not only dependent on the integration of geologic and seismic reservoir characterization techniques, but also on the application of a robust reservoir navigation scheme.

In this paper, we present a case study of the geosteering of a horizontal producer well in a complex reservoir in the deep offshore Niger Delta. The reservoir consists of highly faulted channelized turbidites. The lateral discontinuity of sand bodies and the variations in sand thickness have been calibrated by other producer wells in the field. For efficient geosteering, geological and geophysical well planning was complemented by the availability of scenario modeling, a suitable drilling strategy, the availability of fit-for-purpose drilling and formation evaluation tools, robust software, and a multidisciplinary team with the right mix of experience for effective reservoir navigation. An extra-deep reading azimuthal propagation tool was used, and the inversion was performed with Multi-Component While Drilling (MCWD) software that utilized an algorithm to perform real-time processing of any combination of the deep and extra-deep logging-while-drilling (LWD) resistivity measurements, both coaxial and azimuthal [Sviridov et al., 2014].

The case study primarily reviews the geological and geophysical strategies employed during the geosteering, examines the role the extra-deep azimuthal resistivity inversion modeling and borehole imaging played in understanding the nature of the reservoir and checking the effect of formation anisotropy on depth of detection. The study highlights some peculiarities of the depositional environment of the area and shows the benefits of having extra-deep azimuthal propagation resistivity tools in the bottom hole assembly.
Successful Snubbing Application Performed Underbalanced Fishing of Parted Coiled Tubing in Live High-Pressure Well: Offshore Vietnam
Authors: Wattanasuwankorn Reawat , Daohmareeyor Tuanangkoon , Kritsanaphak Kritsana , Pathmanathan Indran , Bohorquez Jorge
Published: October 2018

Approximately 3,762 m of coiled tubing (CT) became stuck downhole in a live, offshore high-pressure well. The CT parted after fatigue limitations were exceeded.

This paper discusses a snubbing operation that was conducted to fish the parted CT. To ensure flawless execution the following was employed:

Successful job design, operational planning, and execution. A complex engineered solution to improve the fishing operation and clean up debris. Introduction of well control applications (hot tapping) to help minimize risk of pressure becoming trapped in the CT. Multiple successful trials.

A unique job design was introduced and executed according to plan. Careful engineering, study, and yard trials supported the actual operation. The crew's technical expertise helped improve safety and enhanced efficiency.

Significant underbalance skill and fishing proficiency helped make the fishing operation successful. The operator and service company improved their understanding and operational competence by fully communicating with all parties involved.

The operator was able to remove parted CT and perform plug and abandonment (P&A) operations in this live, high-pressure offshore well with no incidents or spills. The successful engineering and testing during this campaign are discussed.
Carbonate Acidizing and Flowback Analysis- A Review and an Evaluation Method
Authors: Aldakkan Bashayer , Al Moajil Abdullah M. , Alnoaimi Khalid
Published: October 2018

Acidizing treatments are the primary technique to enhance production of carbonate formations. Analysis of historical matrix treatment flowback, and laboratory assessment provide insights on the reservoir response to the acid recipe, and thus, positively enhance the selection of fluid recipes. The objective of this paper is to share an evaluation method to assess the effectiveness of an HCl-based acid recipe through experimental studies and flowback analysis.

Gelled, emulsified, and straight hydrochloric acids (HCl) were used to demonstrate the method. Inductively-Coupled Plasma (ICP) was utilized to characterize the liquid flowback samples. HP/HT filter press test was conducted using oil-based and water-based drilling fluids at 150°F to examine the integrity of filter cake and the removal means. Compatibility between crude oil sample and the acid recipe was conducted under reservoir conditions using HP/HT aging cell. ICP analysis was used to correlate the calcium concentration to the magnitude of the rock dissolved by the selected acid recipe.

Filter cake removal using water-based and oil-based drilling fluids showed an effectiveness of 90% and 94.8%, respectively. Clear separation was observed between the oil sample and the acid recipe for the slightly gelled and fresh acid formulas. Calcium and magnesium concentration profile in flowback samples indicated the time when spent acid was recovered. Reduction in calcium concentration suggested calcium-based precipitation occurrence. The pH profile, in combination with density measurements, can assess the optimum shut-in and flowback time for full acid spending and retrieval. Steady pH profile at later times of the flowback revealed the presence of carbonic acid. The iron profile analysis was critical to determine the presence of corrosion products and the origin of iron ions in combination with chromium and manganese ions. Dilution factor of sodium and potassium ion concentration was used to determine water cut in acid flowback samples.
Fracture Optimization Orientated Geosteering within a Fracable Window can Improve Production Performance
Authors: Yao Yanhua , Ning Zhang , Li Qirong , Yang Yang , Jian Zheng , Man Chen , Li Yang , Hao Zhou , Zhou Zhang
Published: October 2018

Production in shale is highly related to the well placement in both sweetspot and fracable zone. Due to both, market conditions and also shale property, geosteering in tight shale reservoirs have generally employed basic and economical steering tools, such as gamma ray; however, though the tool provides some data to steer the well, the data provided does not allow for predictions of fracability and production potential of the shale rock. This paper introduces a new geosteering approach, which augments existing techniques by providing data to also help well placement, then design stage and perforation location. This novel formation evaluation technique is essentially building a quantitative model of "sweetspot fracable window" for shale, which can help to land and target most prospective zones. The main quantitative data is obtained through measurement of cuttings samples at well-site in semi-realtime on a field portable SEM (Ashton et. al., 2013), generating the mineralogical and elemental composition of the samples, and also providing rock textural data. Although cuttings are evaluated after the well being drilled, cuttings are only physical representative rock samples from the bottom of the hole.

Case studies presented in the paper have shown that maintaining the well path in the sweetspot fracable window can result in better well production after fracturing. Thus, the goal for geosteering is to ensure as much as possible that the horizontal well trajectory is maintained within this window. Additionally, the cuttings data generated during the drilling process can also be used both during and after TD to generate optimized completion design, aiming to further maximize well productivity. The cases’ study in this paper also shows that, compared with conventional wireline logging data, the on-location cutting based analysis is able to generate richer mineralogical and elemental data throughout lateral wells, providing a better understanding of geological heterogeneity. Meanwhile, the authors also apply several strategies to calibrate the cutting depths and cuttings’ time lags.

The authors created an approach, which can provide a fast analysis for enhanced reservoir navigation, to keep the well trajectory within a predefined sweetspot fracable zone. The production analysis of the wells, hereafter, verifies that the higher the rate of intersecting into sweetspot fracable zone, the higher production the well receives. This approach then assists in generating cost-effective completion optimization of stage placement and perforation, with the ultimate goal of increasing the investment returns.

In conclusion, the production statistics of the wells verifies the higher rate of intersecting into sweetspot fracable zone, the higher production the well receives. The goal for geosteering is to ensure as much as possible that the horizontal well trajectory is maintained within this window.
The Platform to Optimise the Stranded Well Potential
Authors: Bakar Hasmizah , Watchawong Dangchin , Sahar Raja Nor , Saleh Malaz , Muhaimin Wan Firda , Jeffrey Suzanna Juyanty , Yahia Zaidil
Published: October 2018

During the low oil price period, PETRONAS Carigali Sdn Bhd (PCSB) embarked on an intensified approach to prioritize the production enhancement and idle well reactivation (PE/IWR) activities in its Malaysia operations. To monetize the remaining reserves from these 2,000 active and idle strings, comprehensive opportunity management system which covers opportunity identification, evaluation and prioritization, planning, execution and tracking the activities are implemented.

The identified opportunities from the active and idle wells inventory and integrated field review are initially assessed at a high level based on three criteria, value (the estimated Unit Enhancement Cost, UEC), probability of success and doability which indicates how quickly it will be restored. After the due diligence work completed, the opportunities will progress to the multi-disciplinary technical commercial value assurance committee for approval then followed by planning and scoping the detailed execution. All prioritized, approved and planned opportunities are then turned into execution pipeline and properly tracked into a systematic methodology for post job analysis, evaluating the success of the jobs and recording the lessons learnt for improved future jobs is also addressed in this article.

This article also outlines the examples of comprehensive and successful approach of idle string reactivation activities which gone through this opportunity management system via fishing operation, scale removal treatment, gas lift optimization, behind casing opportunities, acid matrix stimulation and surface facilities rejuvenation. This approach has significantly improved the percentage of active wells in entire domestic operation from 50 to 53%.
Circulating Temperatures in Complex Wellbores: A Quasi-Exact Solution
Authors: Chandrasekhar Sharat V , Suryanarayana P. V. , Sathuvalli Udaya B.
Published: October 2018

Exact solutions are presented for the circulating temperature profiles in an arbitrarily complex deepwater HP/HT well. The methodology is based on coupling multiple segments via interface temperature matching conditions, and can handle deviated wells curvature, tortuosity, variable lithology and multiple geothermal gradients. Frictional heating both at the drillbit and due to the Negative Joule-Thomson Effect are included by coupling the flow hydraulics to heat transfer. These have been largely neglected in previous studies Both forward and reverse circulation scenarios are considered, as are temperature changes across the drill bit at the hole TD. Heat transfer to the ambient and atmosphere above the mudline through the riser are also included in the formulation. Variable fluid thermophysical properties are accommodated by an iterative application of the derived exact solutions. Non-Newtonian flow effects based on the rheological parameters of the fluid are considered in both the hydraulics and heat transfer aspects of the circulating flow.

The method is numerically stable, robust and capable of handling virtually all scenarios in conventional overbalanced drilling. Despite the complexity of the underlying problem, the solution can be implemented in a programmable spreadsheet.

The results show that the circulation rate and inlet temperature have the greatest influence on the circulating temperatures while ROP has a minimal impact because of the pseudo-steady state heat transfer conditions. The key finding is that ignoring frictional effects can result in substantial under-prediction of circulating bottomhole temperatures at higher flow rates, particularly for synthetic/oil-based drilling fluids.
Enhancing Technology Development Process Through Purpose-Built Testing and Training Facilities
Authors: Johnson Austin , Fraczek Justin , Anderson Bo
Published: October 2018

Objectives and Scope

A full-scale test facility is integral during design verification testing of an active Managed Pressure Drilling (MPD) wellbore sealing system as a means to rapidly deploy the technology. The Active Wellbore Sealing System uses a novel sealing element design. Through iterative Finite Element Analysis (FEA) modeling, elastomer composition changes, and immediate feedback from full-scale testing, the first-generation sealing element design performed as intended during its first deepwater field trial in live drilling operations. Further, as the testing took place, the crew was able to prepare and practice planned procedures in a safe environment prior to going offshore.

The test rig facility was upgraded for testing operations with the second-generation Active Wellbore Sealing System. The use of drilling mud combined with simultaneous stripping and rotation of drillpipe under realistic wellbore temperature and pressure enables ‘drilling mode’ testing which exceeds API 16RCD requirements. Use of production equipment at the test rig facilitates automation development to enhance wellbore seal life. Further, trained crews operate the MPD field equipment at the facility and can practice planned drilling procedures. By mirroring the conditions observed in the field, the test rig facility is instrumental in the delivery of project-ready MPD technologies.

Methods, Procedures, Processes

This paper will share test data from the design verification testing program to demonstrate how use of the full-scale test center results in a project-ready system by simulating actual drilling conditions. Additional design verification testing of the second-generation Active Wellbore Sealing System is ongoing at the time of publication of this paper.

Results, Observations, Conclusions

This paper shares results from the design verification testing. The program resulted in successful performance of the sealing element on its first trial. The continued execution of the program reduces the Non-Productive Time (NPT) and cost compared to conventional pilot projects through offline validation, systems integration testing, and ensuring personnel possess the required competencies to efficiently operate the equipment in the field.

Novel and Additive Information

Use of realistic wellbore temperature and pressure with simultaneous stripping and rotating to perform design verification testing was an essential part of the successful first test of the active wellbore seal. Test rig upgrades enable the use of drilling fluid and production equipment to test the second-generation Active Wellbore Sealing System.
Minimising Excess, Mitigating Losses and Improving Cementing Job Quality along Challenging Tophole Sections by a Simplified Novel Spacer-Cement Train: Evaluation of 3 Case Histories Offshore Malaysia
Authors: Brandl A. , Hafizzudin R. Mohd , Mahaiyudin A. Mohd , Hassan H. A.
Published: October 2018

The successful cementation of top-hole sections of three development wells offshore Malaysia has been very challenging since from offset wells nearby the fracture pressure in this section was very low. The section was supported only by an overburden of 328 ft (100 m) of water and 492 ft (150 m) of soil. With such low support, the tophole section had repeatedly hemorrhaged cement into the formation rather than getting good annular cement coverage to surface. As much as 130% more cement than should have been required was wasted in these efforts. In this study we review these case histories and describe how we overcame the given challenges by implementing an innovative spacer cement train.

During drilling of the wells, the inadequate isolation had also allowed as much as 30 bbls/hr of drilling fluids to escape. Analysis suggested that a lighter-weight cement would reduce the pressure on the formation to levels the formation could support, enabling the annulus to be filled with cement without losses. To minimize the losses into the thief zone and to bring up the lead slurry to the desired depth by reducing the equivalent circulating density (ECD) at the top-hole a stable lightweight cementing system was engineered which does not require extenders or lightweight spheres. With this approach we simplified logistics and operations but also brought the quality control of the cementing system to a higher level, since the potential separation between dry-blended lightweight material and cement was no longer of concern.

Laboratory testing was conducted to design this fit-for-purpose solution, which helped to eliminate the amount of synthetic products (such as beads) in the slurry, which greatly reduced its cost. At the same time, the solution provided better properties such as compressive strength development compared to the slurry that had been implemented on previous wells. A sealing spacer system was incorporated into the design to further prevent losses as an additional layer of assurance. As expected, the top-hole sections of the 3 wells were completed with no recorded losses. Cement coverage was confirmed throughout the annulus, and we did not have to pump 130% more cement than required, as we had to on previous wells.

Unlike previously cemented wells in the area with low frac gradient along the top-hole section, the three wells that used the innovative spacer cement train did not suffer subsequent drilling fluids losses because they were adequately isolated. The combined effect of the lightweight cementing system and the sealing spacer was a drastically reduced cement cost and a better ultimate isolation.
An Efficient Gas-Lift MPD Based On Dual-Channel Drillpipe
Authors: Kang Bo , Fan Honghai , Liu Jinge , Wen Zixiang , Deng Song , Wang Shujiang , Chen Yongming , Zhou Yanjun , Feng Guangtong , Li Zongqing , Yan Xiuliang
Published: October 2018

When drilling in the open hole with negative density window, which occurs leakage in the upper section and collapse in the lower section, it will lead to many problems using the conventional method to seal the formation with technical casing, such as high cost,complex casing structure and small completion size. It is difficult to meet the needs of low cost and high efficiency development in the deep wells.

This paper presents a new Gas-Lift MPD drilling method based on Dual-Channel compound Drillpipe (DCP), which can solve the above problems. The DCP is composed of the 139.7mm DCP, the gas lift joint and the conventional 139.7mm drill pipe. It has two circulating channels. Channel 1 is for drilling fluid circulation and channel 2 is directly connected with the upper borehole annulus. The advantage of this method is that it can change the upper wellbore annulus into gas-liquid two-phase flow by injecting gas the channel 2 when the drilling fluid is circulating in the channel 1. It can develop different annulus ECD gradient (small to large) profile and complete complex pressure formation drilling operation in the same open hole section.

According to the design of SBX-5H well, the article uses OLGA to carry out dynamic simulation and analysis of the construction plan of the Gas-lift MPD based on Dual-Channel Drillpipe. The simulation results show that it has great advantages in reducing the number of casing layers, shortening the drilling cycle and enlarging the completion size. Firstly, the control requirements of the ECD profileare is satisfied, which is that the ECD<1.28g/cm3 in the upper section and ECD>1.32g/cm3 in the bottom of the open hole (collapse ECD=1.31g/ cm3, leakage ECD=1.29cm3) by simulating and adjusting drilling pump flow, injected gas flow rate, Dual-Channel Dirllpipe length and drilling fluid density. Secondly, the complicated drilling problem is expected to be solved,such as repeated leakage in the long open hole section. The number of casing layers can be further reduced from 4 to 3 and the drilling cycle is expected to be reduced by more than 20%. Finally, the completion well bore size will be expanded from 149.2mm to 165.1mm (enlarged 11%), which can better meet the requirements of the next production and reservoir transformation.

Through the simulation analysis, it is proved that the Gas-lift MPD technology based on Dual-Channel Drillpipe can effectively solve the problem of negative density window in deep well drilling operation. It not only reduces the drilling difficulties and the drilling cycle, but also is economical and efficient. Therefore, it has a good market prospect.
Integrated Reservoir Modeling while Drilling Enhances Horizontal Well Placement and Productivity in a Complex Offshore Field, Bohai Bay
Authors: Mao Min , Bai Lin Kun , Shen Wen Jian , Li Xiao Qiang , Xia Zhen
Published: October 2018

Horizontal wells are being a common practice in offshore field development in Bohai Bay recently. Maintaining well trajectory in sweep spot while drilling is one of the key factors to optimize horizontal well’s productivity. However, great challenges are often faced in Bohai Bay area including survey uncertainties while drilling and reservoir geology variation. On the one hand, successful placement of a horizontal well requires accurate landing of the well in the right position and orientation in the reservoir. On the other hand, the trajectory is optimized based on structural geobody variation resulted from the uncertainty of parameters governing the static behavior of the field. Therefore, the ability to update geosteering model in timely manner and to proactively adjust well trajectory in real time are required.

This paper presents an innovative method in Bohai Bay by applying the technology of integrated seismic volume and reservoir geosteering model while drilling to achieve very promising productivity. That is to say, the new geosteering method includes seismic inversion of checkshot calibrating, single/multi-wells reservoir model updating, conventional logging while drilling, and mud logging etc. How to develop new horizontal well steering methodology and software integrated seismic volume of time (or depth) domain, logging while drilling, reservoir modeling result to optimize well planning and placement for high productivity?

Results from lower Neogene Minghuazhen formation tests executed in SuiZhong 36-1, Bozhong oilfield of Bohai Bay clearly demonstrate the following capabilities of the technology.Reduction of the steering need for the tools of distance to boundary included Directional and deep well placement tool.A bridge from three-dimensional geology model to two-dimensional geosteering model before drilling; vice versa, 2D geosteering model update 3D geological model after drilling.

More People grasp the systematical methodology of integrated reservoir geosteering model and trajectory optimizing while drilling which provide a higher degree of confidence in the drilling process.