bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Innovative Approach to P&A Barrier Verification and Cement Plug Placement Utilising In-Situ Completion Strings: A Case Study
Authors: Imrie Andrew , Kamaludin Ashikin , Hood Andrew , Agnew Alistair 
Published: March 2021

Abstract
Traditional evaluation of behind-casing cement bond quality prior to cement plug placement involves removal, storage, transportation, and disposal of the tubing completion string. This paper presents an innovative approach to verifying cement bond and subsequent cement plug placement. This method involves cutting and retrieving part of the completion string and deploying acoustic logging tools into the casing, followed by using the tubing as a cement stinger.
The procedure described in this paper first involves plugging and cutting the tubing, followed by partial retrieval of the completion to expose the abandonment horizon, which may be an impermeable shale or salt layer. A radial cement bond log tool is conveyed on wireline out of the tubing cut in order to evaluate the cement bond behind the exposed casing section. The existing cement sheath is assessed in accordance to a cement evaluation criteria to determine suitability as a barrier. A balanced cement plug is pumped utilising the existing completion string rather than a dedicated stinger. The permanent barrier is then verified appropriately based on satisfying key metrics in the pumping operation before hanging off the completion tubing in-hole and progressing with the rest of the abandonment programme.
In the case study presented here, the tool string design considered the need to pass completion restrictions, convey through production tubing, and remain centralised with up to 50-degree deviation. Analysis of cement bond log data indicated that bond quality was good and suitable to place an internal cement plug across the abandonment horizon. This satisfied a minimum of 200-ft coverage across the zone of interest. The existing deep-set mechanical plug placed in the tubing prior to tubing cut was utilised as a base for the cement barrier. A 2,000-ft balanced cement plug was successfully set across the zone of interest. The completion tubing was used as a conduit for cement slurry placement, eliminating the usage of a dedicated work string. At the end of displacement, the tubing string was pulled out of hole safely to approximately 500-ft above the top of the cement with the help of controlled-gel progression properties incorporated in the slurry design. Due to existing completion accessories, setting a through-tubing cement plug and tubing rotation is not an option. Expandable cement was pumped to mitigate natural shrinkage and enhance post-set cement expansion to ensure a competent barrier. The cement job objectives were achieved by meeting the cementation execution criteria with no requirement to wait on cement. This provides additional time saving to the well abandonment.
The discussed approach has successfully realised a significant rig-time saving of approximately two days on each well. Going forward, the methodology has effectively been applied to multiple wells across the Southern North Sea (SNS).
The Transient Dynamics of Permanent Fiber Temperature Analysis and Downhole Gauge Evaluation of an Acid Stimulation Job in a Brown Field, Offshore Malaysia
Authors: Ting Chang Siong , Minggu Nur’ain , Kamat Dahlila , Riyanto Latief , Tan Chee Seong , Kalidas Sanggeetha , Kamarulzaman Ammar , Goh Gordon Kim 
Published: March 2021

Abstract
Well B-2 is a dual-string producers with Distributed Temperature Sensing (DTS) fiber installed along the long string (i.e. Well B-2L) across the reservoir sections. Each zone comprises of sub-layers. This system enabled the operator to continuously monitor the wellbore temperature across all the producing intervals including gas-lift monitoring, well integrity identification, zonal inflow profiling and stimulation job evaluation. This paper mainly discusses the post matrix acid stimulation job with interpreted DTS and zonal Permanent Downhole Gauge (PDG) data.
Well B-2L has been selected for matrix acidizing treatment to improve the productivity due to potential formation damage, proven by the declining production over the years. Prior to the execution of the acidizing job, several conformance jobs such as injectivity test, tubing pickling were performed. This is followed by the main acid treatment and flow back. DTS & zonal PDG data were acquired throughout the operation. A transient simulator model was built incorporating all the reservoir properties including well trajectory and completion schematic to analyze the DTS profile and understand the zonal inflow profiling for each zone post treatment. A baseline temperature was acquired for the geothermal evaluation. The DTS data has been studied according to actual event schedules. Some significant findings are; i) completion accessories effect (feedthru packers) creates temperature anomalies, ii) leak points detected at top producing zone signifies cooling effect due to injected fluid. The main treatment was intended at zone 2 and 3 using nitrified acid. However, leak points at top zone caused bypassed injection into Zone 1 and 2 instead. Fiber optic DTS warmback profiles post main-treatment was analyzed to quantify the fluid intake from sub-layer in each zone.
Qualitatively from the DTS-interpreted zonal profiling, the data clearly shows most of treatment fluid is being injected into Zone 1 and 2 with no intakes at Zone 3. Furthermore, warmback analysis confirmed the high intake zones from sub-layers within the main zone based on the permeability contrast. This paper will further discuss the zonal injectivity understanding for improvement from the zonal-inflow profiling evaluation by incorporating DTS, PDG and surface production data.
Applications of a Novel Lost Circulation Additive
Authors: Zhu Qi 
Published: March 2021

Abstract
Lost circulation is a complicated situation in the drilling operation, wasting a lot of time and mud during processing. A serious lost circulation can cause hazards, such as sticking, blowout and collapse of well. There are some problems in conventional plugging technology, such as particle size of plugging material does not match crack width, slip of the blocking zone, and weak adhesion of lost circulation additive to the rock, which restricts the success rate of lost circulation operation.
Regular and elastic polyhedron structure material compounds elastic variable network plugging material and rigid plugging materials to form a loss circulation materials (LCM)plugging mixture for different leakage speed and crack width affected by stress.
Through plugging and HTHP sand bed experiment loss circulation materials(LCM) and amount of gel were optimized and improved. Through indoor simulation about leakage process of different leakage speed and different crack sizes, the on-site construction formula suitable for wells under different temperature is formed and determined.
Scanning electron microscope shows the plugging gel has a variable network structure. By changing the ratio of elastic plugging material, rigid plugging material and gel, a LCM plugging formula for high temperature and high pressure formations can be formed to meet the pressure requirement of 7.5MPa. Leakage simulation formed on-site plan under different leakage rate to adapt to 180°C.
The novel CPM material has been well-field tested and used for HPHT reservoirs. When the rate of leakage less than 30 m3/h and 30-60 m3/h, success rate of single plugging is more than 95% and rate of leakage greater than 60 m3/h success rate of single plugging beyond 80%. Leakage loss time is more than 80% shorter than conventional plugging techniques.
Peripheral Low Salinity Water Injection Handil Case Study
Authors: Sianturi Julfree , Handoko Bayu Setyo , Suardiputra Aditya , Senoputra Radya 
Published: March 2021

Abstract
Handil Field is a giant mature oil and gas field situated in Mahakam Delta, East Kalimantan Indonesia. Peripheral Low Salinity Water injection was performed since 1978 with an extraordinary result. The paper is intending to describe the success story of this secondary recovery by low salinity water injection application in the peripheral of Handil field main zone, which successfully increased the oil recovery and brought down the remaining oil saturation beyond the theoretical value of residual oil saturation number.
Water producer wells were drilled to produce low salinity water from shallow reservoirs 400 - 1000 m depth then it was injected to main zone reservoirs where the main accumulation of oil situated. This low salinity water reacted positively with the rock properties and in-situ fluids which was described as wettability alteration in the reservoir. It is related to initial reservoir condition, connate water saturation, rock physics and connate water salinity. This peripheral scheme then observed having the sweeping effect on top of pressure maintenance due to long period of injection.
The field production performance was indicating the important reduction of residual oil saturation in some reservoirs with continuous low salinity water injection. From static Oil in Place calculation, some reservoirs have high current oil recovery up to 80%. This was proved by in situ residual oil saturation measurement which was performed in 2007 and 2011. It was indicating the low residual saturation as low as 8% - 15%. This excellent result was embraced by a progressive development plan, where water flooding with pattern and chemical injection will be performed later on.
The continuation of this peripheral injection is in an on-going development with patterns injection which is called water flooding development. An important oil recovery can be achieved with a simple scheme of low salinity injection, performed in a close network injection, where the water treatment is simple yet significant oil gain was recovered. This innovation technique brings more revenue with less investment compared to chemical EOR injection.
Toward Developing Non-Corrosive Acid System for Complex Scales Removal
Authors: Gamal Hany , Elkatatny Salaheldin , Al-Afnan Saad , Bahgat Mohamed 
Published: March 2021

Abstract
Oil and gas industry deals with fluid streams with different ions and concentrations that might cause scale precipitation. The scale precipitation, will thereafter, affect the fluid flow characteristics. Many problems will be raised by the scale deposition that affects the overall petroleum production.
This paper aims to develop a non-corrosive acid system with high dissolution efficiency for field complex scales. The paper provided a series of lab analysis that covers the compositional analysis for the collected scale sample, and evaluating the developed acid system for compatible and stable properties, dissolution efficiency, and the corrosive impact. A field scale sample that has a composite chemical composition of calcium carbonate, calcium sulfate, kaolinite, barium sulfate, magnetite, and halite with different weight percentages by employing the diffraction of X-ray technology.
Developing the new scale dissolver was achieved by specific compositional study for the organic acids to achieve high dissolution efficiency and low corrosive impact for the field treatment operations. The study results showed the successful scale removal for the developed dissolver at 160 and 210 °F by dissolution efficiency 100 % for 5 hours. The fluid showed a stable and compatible performance with low rate of solids precipitation after the scale treatment (2.3 %). The developed dissolver has a pH of 9. The corrosion test was conducted without any scale inhibitors and the results showed the low corrosion effect by 0.0129 lbm/ft2. The obtained successful results will help to dissolve such complex field scales, maintain the well equipment, and maintain the petroleum production from scale issues.
Navigating the Depleted Fracture Gradient During Operations: From Concept to Drilling, Open Hole FIT Management & Cementing
Authors: O'Reilly Gerard , Chan Alvin W. 
Published: March 2021

Abstract
Depleted Fracture Gradients have been a challenge for the oil and gas industry during drilling and cementing operations for over 30 years. Yet, year after year, problems related to lost circulation, borehole instability (low mud weight due a low fracture gradient), and losses during cementing operations leading to NPT and remedial work continue to rank as some of the top NPT events that companies face. This paper will demonstrate how the geomechanical modeling, well execution and remedial strengthening operations should be implemented to provide for a successful outcome. The use of a Fracture Gradient (FG) framework will be discussed, and the use of a negotiated fracture gradient will highlight how the fracture gradient can be changed during operations. This paper will also show actual examples from Deepwater operations that have successfully executed a detailed borehole strengthening program. Through our offset studies and operational experience, we will provide a format for navigating complex depleted drilling issues and show an example on recovering from low fracture gradients.
This paper will demonstrate (1) how our framework facilitated multi-disciplinary collaborative discussion among our subsurface and well engineering communities; (2) how the impacts of drilling fluids and operational procedures can change this lost circulation threshold; and (3) how our negotiated FG approach has successfully delivered wells drilled in narrow margins.
Autonomous Inflow Control Valve Applications Creating Better Wells: A Review of Design Optimization and Associated Benefits
Authors: Abd El-Fattah Mahmoud , Fahmy Ahmed Moustafa , Wahaibi Hamed , Shibli Abdullah , Zuhaimi Khaled 
Published: March 2021

Abstract
One of the largest oil fields in the GCC was developed in the 1960's. The field was initially produced under natural depletion supplemented by gas injection. The high offtake rates led to a rapid displacement of the gas/oil contact; thus, the field has now been suffering from early gas/water breakthrough and uneven fluid influx along with the horizontal wells. The reservoir has been on production for more than 50 years. Water/gas breakthrough from fractures being the major challenge which negatively affects wells oil production rates. Applying technology which can manage water/gas breakthrough in a cost-effective manner whilst allowing increased oil production was a key goal from operators in this field.
Passive Inflow Control Devices (ICD) were introduced to the global oil and gas market in mid/late-1990's, and the first generation of Autonomous ICD (AICD) that can help reduce more unwanted gas or water was first installed in 2007. ICD's successfully demonstrated that they could delay the gas and/or water breakthrough within horizontal wells, but they could not choke gas when the coning/gas-breakthrough occurred and along with limited abilities to stop unwanted water production. To help solve this problem, the Autonomous Inflow Control Devices (AICD-RCP) with a movable disc was introduced to the market and demonstrated reduction of gas production by 20-30% with similar gains in oil production[1]. In this paper, the newest generation of Autonomous Inflow Control Valve (AICV) technology is presented. The AICV technology has a movable piston that can close and reduce the unwanted gas and water production by up to 95%[2]. The application of AICVs discussed herein were deployed within several wells which had extremely high Gas Oil Ratio (GOR) and low oil production. The novel AICV technology can differentiate between fluid types based on viscosity and density. When undesired fluid (gas and/or water) starts to be produced, the AICV chokes the valve flow area gradually until completely shutting off, all without well intervention[3].
Well production performances are documenting the benefits of installing AICV completions. The results demonstrate the AICVs closing the zones with high gas production and favoring oil-rich zones. Majority of evaluated wells demonstrated clearly that the extremely high GOR was reduced; some wells have returned to solution GOR for more than two years, and at the same time, the daily oil production is increased.
A New Methodology for Calculating Wellbore Shut-in Pressure in Numerical Reservoir Simulations.
Authors: Kayode Babatope , Jamiolahmady Mahmoud 
Published: March 2021

Abstract
In low permeability reservoirs, the pressure transient response of the build-up takes a long time to stabilize. During the history matching process, the observed non-stabilized build-up pressure cannot be compared to simulated well block pressure (WBP). This challenge arises because most reservoir simulators convert the WBP of flowing wells to wellbore pressure using Peaceman’s equation, but do not perform this conversion for build-up pressure data. Such conversion is particularly important for low permeability reservoirs. This paper discusses a new method to calculate the wellbore pressure of shut-in wells and highlights its benefits.
A full superposition equation for analytical wellbore-pressure, without the usual logarithmic approximation of Ei function, is the basis of the mathematical formulation proposed here. A modified equivalent radius concept together with the superposition principle are used to arrive at an expression to calculate numerical wellbore pressure from simulated WBP. To verify the validity of the approach, the calculated numerical wellbore pressure data is compared with analytical wellbore pressure build-up data described by the Horner function.
The results show that numerical wellbore pressure is in better agreement with the non-stabilized observed pressure data than WBP. This is because WBP is an average pressure over a spatial distance in which theoretical pressure varies as a logarithmic function of distance. Therefore, when the grid size is large and spatial pressure gradient is significant (as the case in low permeability reservoirs), simulated shut-in WBP may be very different from observed shut-in wellbore pressure measured by a downhole gauge. Our results demonstrate that this difference increases with increasing grid size. If, during numerical well testing, numerical wellbore pressure is used for the log-log pressure derivative plot instead of WBP, the early distortions of infinite acting radial flow (IARF) stabilization, which has been observed by some investigators is eliminated.
In summary, the presented methodology to calculate shut-in wellbore pressure is practically attractive to complement existing simulator capabilities for relating wellbore pressure to well block pressure. The use of numerical wellbore pressure instead of WBP, which is currently used, eliminates the need to apply the time-shift proposed by some investigators to correct IARF signature deviation, and observe the true flow regime.
Delivering More Fit-for-Purpose Wells with Low Cost Approach at Untapped Area Matured Field – Application of Cone Concept Statistical Approach
Authors: M. Yusof M. Hatta , Sulaiman M. Zarkashi , A. Halim Rahimah , Ahmad Fauzi Nurfaridah , Sella Thurai Ahgheelan , Mahictin Masseera , Tg Yahya Tg Zuhaili , Muslim Fadli Adlan 
Published: March 2021

Abstract
This paper discusses the Case study of Field A in offshore Sarawak, Malaysia which focus on re-thinking development based on statistical analysis of the fields. Conventionally, well design is driven by subsurface requirement by targeting the high-reserve sand and well is designed to meet subsurface objectives. However, the conventional way may not be efficient to develop matured field environment due to the high CAPEX and the inconsistencies among well design especially in current volatile oil price period. The objective of this fit-for-purpose approach which is called "Cone Concept Statistical Approach" is to steer away from the conventional way of targeting only sweet spots whilst leaving the remaining potential resources undeveloped. Based on the statistical analysis and subsurface fields pattern, the "Cone Concept Statistical Approach" in which standardizing well design and trajectories was developed to extract the whole fields’ reserve at maximum. Well design boundaries were introduced to ensure this approach can be replicated throughout the field. Not only this study covers drilling perspective, completion perspective was also taken into consideration by exploring a cheaper and fit for purpose sand control method, considering it is a matured field with relatively short remaining field life. The Well Cost Catalogue for this field-specific approach was also developed which contains different types of design and completion, in order to holistically evaluate sand control method and identify the best option for the project moving forward.
This "Cone Concept Statistical Approach" aims to enable operator to drill simple wells within the same allocated budget in which poses low-to-no risk in the design and execution phase. This promotes a learning curve to improve operation & HSE, and ultimately gets positive project economics. Since this simple approach can be implemented early on even during the pre-FEL stage, the FDP team & host authority can come together to jointly discuss the targets/platform ranking and segregate them into various phases. Hence, the number of platforms or drilling centers, and its location also can be optimized early on with this concept, and again, translating into further reduction in overall project cost. This paper will help other operators and host authority to understand better on how a specific development concept on statistical approach can result and turn the matured-challenging fields into more economically attractive projects – low overall development cost and maximizing the recovery.
A Dynamic Workflow of Well Health Issue Prediction – Sulfur Deposition
Authors: Haq Bashirul 
Published: March 2021

Abstract
Sour gas reservoirs are vital sources for natural gas production. Sulphur deposition in the reservoir reduces a considerable amount of gas production due to permeability reduction. Consequently, well health monitoring and early prediction of Sulphur deposition are crucial for effective gas production from a sour gas reservoir. Dynamic gas material balance analysis is a useful technique in calculating gas initially in place utilizing the flowing wellhead or bottom hole pressures and rates during the well's lifetime. The approach did not apply to monitor a producing gas's health well and detect Sulphur deposition. This work aims to (i) modify dynamic gas material balance equation by adding the Sulphur deposition term, (ii) build a model to predict and validate the issue utilizing the modified equation.
A unique form of the flowing material balance is developed by including Sulphur residue term. The curve fitting tool and modified flowing gas material balance are applied to predict well-expected behaviour. The variation between expected and actual performance indicates the health issue of a well.
Initial, individual components of the model are tested. Then the model is validated with the known values. The workflow is applied to active gas field and correctly detected the health issue. The novel workflow can accurately predict Sulphur evidence. Besides,the workflow can notify the production engineers to take corrective measures about the subject.
Keywords: Sulfur deposition, Dynamic gas material balance analysis, Workflow