bluuebunny/crossref_metadata_2025 huggingface dataset:
Successful Field Application of Pillar Fracturing Technique in Water Injection Well for Creation of Highly Conductive Conduits
Authors: Bhagavatula Ramkamal , Rajagopalan Vijay Shankar , Chellappan Suresh , Al-Ashwak Amna , ElMofti Mohamed , Boueshi Alaeldin , Eid Waleed , Allam Ahmed , Abdelbaky Amr , Davis John
Published: October 2018

This paper discusses the successful application of a pillar fracturing technique in a water injection well wherein a major operator previously experienced poor injectivity within the target zone.

The aim of the pillar fracturing technique was to achieve the highest possible fracture conductivity to enhance water injectivity for reservoir pressure maintenance. This technique creates infinite conductivity channels with proppant distributed within the fracture as aggregates or groups separated by clean fluid. These proppant groups function as pillars to hold the fracture open and help enable fluid flow in the open channels between proppant pillars. The conductivity of a partially open fracture with proppant pillars can be several orders of magnitude greater than that of a conventional fracture filled with proppant after closure. After a pillar style hydraulic treatment, the propping agent remains in the fracture grouped to form pillars because of the sticky resin that was applied to the proppant just before being blended (intermittently) into the fluid system that was pumped during the treatment. This helps the grains in the resulting pillars to adhere together and help prevent the fracture from entirely closing, forming open conduits for fluid flow. The overall success of this fracturing stimulation treatment depends on the sequenced pumping technique, allowing the propping agent to form proppant aggregates during their placement into the formation.

This paper presents the enhanced pillar fracturing technique, pre-job well analysis and design, Minifrac data calibration, and actual pumping operation execution. The well intersects a reservoir with sandstone lithology that had not been fractured previously. The sandstone formation is subdivided into three intervals of 60, 40, and 60-ft thickness, with distinct shale layers separating them. Based on the log interpretations and formation geomechanical analysis, two pillar fracturing stages were determined necessary to treat the entire targeted formation and maintain balanced injectivity in all three intervals. An optimum hydraulic fracturing design was developed and executed to deliver optimal well performance. Actual operational execution involved use of specially designed surface equipment and adhesive enhancement proppant coating to install highly conductive flow paths while maintaining reservoir and proppant pack stability. This resulted in a successful treatment that sustained 16,000 barrels of water injection per day (BWIPD).

The successful application of the pillar fracturing technique in this well motivated the operator to extend the pillar fracturing technique to other injector and producer wells.
Inflatable Packer Anchor System Enables Rigless Installation of an Insertable Progressing Cavity Pump in South Oman
Authors: Osorio Alejandro , Ford Francis , Montilla Benigno Segundo
Published: October 2018

Current market conditions in the oil industry call for cost effective well intervention methods to optimize production in wells completed with Insertable Progressing Cavity Pumps (I-PCPs). Rigless rod-string conveyance of I-PCP's traditionally rely on Pump Seating Nipples (PSNs) or mechanical-set I-PCP anchoring devices in wells without PSN's. Although the installation of an I-PCP on a PSN is a reliable method, it requires a PSN to be originally installed within the production tubing, which limits the I-PCP setting depth to the location of the PSN. Rod-string conveyance of mechanical-set I- PCP anchoring devices is limited by the rod string's effectiveness to transmit the required axial loads to setting depth, which becomes increasingly challenging in extended-reach conditions. Other challenges with I-PCP installations include location of previously installed PSN's and positive anchoring to facilitate disengagement of the rotor without unseating the I-PCP for flush-by operations.

An inflatable packer anchoring device has been developed to simplify rigless installation of an I-PCP without the need of a seating nipple. The device relies only on hydraulic pressure while eliminating the need for axial loads during its setting sequence. The rod string deployed inflatable packer I-PCP anchoring device incorporates inflatable packer technology in conjunction with a hydraulically-actuated slip mechanism. It is equipped with seal cups and a shearable intake sub to obtain the required pressure competence to confirm tubing integrity and enable its setting sequence while maximizing flow-through capability after it is set. The system can be retrieved by applying overpull to shear its release pins allowing the inflatable packers to deflate and the mechanical slips to retract.

The first installation of this system proved its optimal functionality by successfully setting an I-PCP in 3-1/2" production tubing in a vertical well in Oman's Sadad field. The I-PCP was deployed on rod string in conjunction with the inflatable packer anchoring device to setting depth. The system was set by applying pressure with a flush-by unit pump via the tubing-rod annulus, and the well was immediately placed into production.

The objective of this paper is to provide a technical explanation of this innovative and unique technology, share the lessons learned from its first installation, and discuss its potential to improve the current capabilities of I-PCP technology while reducing operational cost and optimizing PCP/I-PCP completion design.
A Rigorous Yet Simple Technique for Coupled Reservoir and Geomechanics Simulation
Authors: Matsunaga Ryotaro , Watase Seishiro , Furui Kenji
Published: October 2018

Many applications in the petroleum industry require both an understanding of the porous flow of reservoir fluids and an understanding of reservoir stresses and displacements. Historically reservoir simulation has accounted for geomechanical effects by simple use of a rock compressibility. This assumption results in pore volume to change only with pore pressure. On the other hand, according to the poroelasticity theory, pore volume should change not only with pore pressure but also with confining stresses or volumetric strains induced by rock deformation. This difference in the governing equations poses a great challenge when coupling reservoir flow and geomechanics models.

In this study, we develop a mathematical expression that relates the pore volume compressibility used in the porous flow equation to poroelasticity parameters defined in the geomechanics model. Secondly, in order to implement consistent pore volume changes between the reservoir flow and geomechanics models, we derive a pore volume correction term for the porous flow equation, which accounts for volumetric strain changes and rock matrix deformation. As demonstrated in the paper, the correction term can be easily implemented in sink/source terms (or "fictitious well" term), which are readily available for most commercial reservoir flow models. With this simple implementation, virtually any existing commercial reservoir simulation models can account for geomechanical effects via modular coupling techniques.

In this work, we compare three different techniques for coupling reservoir flow and geomechanics. One technique uses an explicit algorithm to couple reservoir flow and displacements in which flow calculations are performed every time step followed by displacement calculations (i.e., One-way coupling method). A second technique uses an iteratively coupled algorithm in which flow calculations and displacement calculations are performed sequentially for the nonlinear iterations during each time step (i.e., Iterative partitioned coupling method). The third technique uses a fully coupled approach in which the program's linear solver must solve simultaneously for fluid-flow variables and displacement variables (i.e., Monolithic coupling method). Using Mandel's problem, example simulations are presented to highlight accuracy and computational efficiencies in these coupling techniques.

To the best of the author's knowledge, this is the first paper to present a coupling technique to consider rigorous geomechanical effects in the porous flow equations. The coupling method proposed in this study can be applicable for virtually any existing reservoir and geomechanics simulation models. The proposed coupling techniques are easily extended to multiphase flow and poroelastoplastic problems. All problems in this paper are described in detail, so the results presented here may be used for comparison with other geomechanical / porous-flow simulators.
Optimisation of Engineered Water Injection Technique in Carbonate Reservoirs: A Case Study
Authors: Adegbite Jamiu Oyekan , Al-Shalabi Emad Walid
Published: October 2018

Engineered/low-salinity water injection technology is one of the latest promising techniques for improving recovery in both sandstone and carbonate reservoirs. In this paper, the optimization of engineered water injection technology is investigated using three 5-spot reservoir models including heterogeneous with channeling, heterogeneous with gravity underride, and homogeneous. The net present value was chosen as an objective function for the study. 18 design parameters were selected for the study including reservoir, operational, and economic parameters. The machine learning and artificial intelligence tools were utilized. Response Surface Methodology and Designed Exploration and Controlled Evolution algorithms were implemented for sensitivity analysis and optimization studies, respectively.

The sensitivity study showed that oil price, tax rate, and initial oil saturation are among the most significant design parameters on the net present value for the three models investigated. Moreover, the findings showed that developing the gravity underride model requires more attention as being the most sensitive model with 13 influential design parameters. The optimization study highlighted the need for engineered water injection in the secondary mode to achieve the best profitability out of the three models. Also, it is recommended for an operator to invest in the homogeneous, followed by the channeling, and least the gravity underride models due to the corresponding net present values of $1.44 million, $1.39 million, and $0.96 million, respectively.

The study highlighted the importance of selecting the most suitable objective function for achieving the project profitability by comparing net present values vs. oil recovery as objective functions. In addition, this study can be used as a guide for using artificial intelligence tools to understand the most influential engineered water injection design parameters that affect profitability, and hence field scale developments can be conducted with more certainty and lower risk.
Maximizing Oil Recovery through Gas-Cap Perforation in Strong Water-Drive Reservoir
Authors: Abdulhadi Muhammad , Mansor Mohd Najmi , Amiruddin Nurul Azrin , Tran Toan Van , Jacobs Steve , Abd Wahid Muhammad Izad , Usop Mohammad Zulfiqar , Zamzuri Mohd Dzulfahmi , Dolah Khairul Arifin , Munandai Hasim , Yusop Zainuddin
Published: October 2018

Reservoir X-7, a watered-out reservoir in Field B, was successfully revived by perforating the original gas-cap zone to maximize oil recovery, which increased the recovery factor (RF) from 40% to 46%, resulting in approximately 2,300 BOPD through multiple perforations.

Maintaining the oil column sandwiched between gas and water is the standard practice to maximize oil recovery in a strong water-drive reservoir. Despite having a strong aquifer and a thick gas cap, Reservoir X-7 has produced continuously for 30 years without any gas reinjection. The reservoir was producing at 99% watercut, indicating the original oil column was already swept. Subsequent material balance study and saturation log results confirm that oil migrated into the original gas cap. Given the reservoir condition, an unconventional approach was proposed to produce the oil column through the original gas-cap zone.

The first gas-cap perforation for Well B-07 successfully produced 500 BOPD, so it was decided to perform three additional perforations (additional perforations) for Wells A-01, B-12, and B-16, which were successful with a total 2,000 BOPD oil gain from the three wells. Subsequent additional perforations was performed in Well B-07 after the original additional perforations watered out. However, the new additional perforations and subsequent ones in Well B-11 resulted in gas rather than oil. Both wells were shut in. Once the new perforations are watered out, the remaining oil potential in Reservoir X-7 will be confirmed by reopening well B-07 and B-11 until either oil or water is produced. The approach has so far provided approximately 2,300 BOPD of incremental oil production, extending well life by more than 24 months and allowing the RF to increase from 40% to 46%. It delivered encouraging results and opened up opportunities for other reservoirs.

This paper provides valuable insight into the case study and lessons learned in terms of maximizing oil recovery using original gas-cap perforation. This approach is highly recommended as the production enhancement method for maximizing oil recovery, particularly in mature fields with similar reservoir conditions.
Fracture Height Growth Study: Cooper Basin Probability Analysis
Authors: Griffiths James
Published: October 2018

A probability graph was developed to describe height growth potential when performing hydraulic fracture stimulation operations in the Cooper Basin, Central Australia. This graph has led to improvements in setting completion strategies.

Multiple data sources were used to define the probability graph, including proppant tracers, microseismic, downhole tiltmeter data as well as pressure interference and production data. Each dataset has known uncertainties, so the empirically derived probability graph has an intrinsic range of uncertainty.

The observed data shows instances of fracture propagation across changes in lithology which were previously thought to be highly confining. In other instances, field data closely matched model predictions. Likewise, the observed data indicates that typical levers used to induce or reduce height growth (such as fluid viscosity, pump rate and job size) may have limited influence. These insights led decision makers to question the validity of deterministic fracture models.

This study highlights that fracture height growth predictions should carry a range of uncertainty. An appreciation of this range has proven beneficial by fostering ‘what-if’ discussions during the project planning phase. The derived probability graph can be used to run sensitivity analyses to determine the optimal path when several completion methods are available.

This graph has proven to be an informative and practical tool for use in the Cooper Basin by promoting deeper thought and collaboration amongst stakeholders. Similar tools could be developed to characterise fracture height growth within other petroleum basins.
Produced Water Reinjection at Wellpads: Leverage Terminal Liquid Handling & Accelerate Oil Production from MBA Fields
Authors: Mehta Nirav , Ray Rimjhim , Kapadia Gautam
Published: October 2018

Oil, water and gas separation at wellpads with improved technology and compact design has significant advantage for increasing liquid handling from group gathering wellpads and accelerating oil production from fields. Cairn, Oil & Gas vertical of Vedanta Limited is the Operator of RJ/ON block in India with major fields Mangala (M), Bhagyam (B) and Aishwariya (A). Mangala field (75% of MBA production) is the largest onshore oil discovery in India and Bhagyam-Aishwarya fields together contribute to ~25% of the total MBA production. The MBA fields are on water + polymer flood and gradual increase in water production is challenging to process the same oil production volumes. Future field development plans in these fields requires debottlenecking of liquid handling constraints.

The current paper depicts the fast track modifications planned in various fields and its implementation carried out in Aishwariya field which was limited for produced fluid handling due to capacity constraints at the centralized processing well-pad 8 (AWP-08). These modifications were aimed towards localized produced water treatment and reinjection of 30,000 barrels per day (bpd) into the existing injection manifold at Aishwarya Wellpad. In the first stage, produced water is separated from 3,000 ppm to 300 ppm OIW and in second stage from 300 to <100 ppm OIW with <5 ppm TSS. The existing vessels were retrofitted and modified in field with internals like inlet device, calming baffles, coalescing pack, overflow weir and oil bucket. This enabled additional residence time suiting the given fluid characteristics and efficient separation of the produced fluids. This resulted in accelerating oil production from the field by ~2,000 bopd by opening more shut-in wells and leveraging terminal liquid handling capacity. And with the future ESP upsizing and more infill wells coming online, there is further potential to gain additional oil upto 3000 bopd. The execution of Project commenced in Sep-17 and was commissioned in Dec-17 in a record 3 months’ time period including engineering which helped in monetizing early oil production benefit. Based on the success of the local pad separation in Aishwariya field, similar scheme is planned to be implemented in Mangala & Bhagyam wellpads and other small fields with high water production.
Intelligent Waterflooding Development of High-Permeability Reservoirs at the Late Development Stage
Authors: Jia Deli , Guo Tong , Pei Xiaohan , Zhang Jiqun , Ye Qinyou , Jin Xian'gao , Tang Xiaohong
Published: October 2018

In China, the initial development program was "early zonal water injection" for the reservoirs with insufficient natural drives and low formation-saturation pressure differential. At present, the oilfields have successively been progressing into the late development stage with high water cut. Especially in high-permeability reservoirs, water fingering through a single layer results in poor development response. The objective of this paper is to efficiently control invalid water cycling and realize a smooth flooding profile. A technology for whole-process monitoring and controlling in zonal injection has been developed for waterflooding reservoirs based on cable-controlling approach. This technology can constantly monitor real-time flowrate, cumulative volume injected, tubing pressure and casing pressure, as well as intelligently adjust the injection rate according to the allocation in the development program, thereby realizing fine zonal injection. As a demonstration, a typical block characterized by the high permeability (~100 mD in average) and being at the late development stage with high water cut (96.8%), was chosen to conduct the follow-up study and evaluate waterflooding efficiency of high-permeability reservoirs.

There are 54 water injectors connected to 98 oil producers in the demonstration block. The data for one consecutive year upon implementation of the technology were collected and then analyzed. The analysis results illustrated that the water absorption profile was improved and the water fingering was efficiently controlled. The monthly rising rate of the composite water cut in the demonstration block decreased from 0.1% (value before the implementation) to 0.02%, and even to −0.027% in some individual well groups (which means the composite water cut was reduced); 77.5% of sandbody thickness in some individual wells has been producing, compared to 50.7% before the implementation, achieving remarkable effect. As can be seen, this technology is of great guiding significance for waterflooding development of high-permeability reservoirs at the late development stage with high water cut.
Development and Application of Key Equipment of CO2 Waterless Fracturing
Authors: Zheng Lichen , Meng Siwei , Chen Shi , Yang Qinghai
Published: October 2018

Water is essential for energy exploitation, and moreover the contradiction between water resources and energy recovery seen in China is more severe than those in other countries. Given this, CO2 waterless fracturing, which improves the production and recovery factor of an individual well and meanwhile serves for water preservation and CO2 underground storage, can contribute to the sustainable development of China's oil industry.

The continuity and reliability of equipment is a key technical aspect for the successful waterless fracturing, in which the operation is required to be done in a sealed, pressurized environment during the whole workflow, and the proppant-carrying capability of fluids is low. Therefore, strict requirements are raised up upon the equipment. On the basis of the dynamic fluid balance combined with the fluid phase evolution during the whole construction workflow and its effects on stimulation treatments, this paper optimized the design of key construction equipment, such as CO2 storage tanks, booster pumps, sealed blender trucks and fracturing pump trucks.

Major improvements can be concluded as: 1) the vertical tank is used for the sealed blender, which enhances the control stability of sand supply process jointly by the pressure difference regulation and auger; 2) booster pump unit with high pump-rate capability are included in the system for liquid supply and fluid phase control; 3) the liquid supply combines the mobile transport tanks and fixed storage tanks to increase the liquid supply capability; 4) the fracturing system is equipped with eight special fracturing pumps for waterless fracturing, fulfilling the construction requirement of 20,000 hydraulic horse power. The whole equipment system has treatment capability of available pump rates up to 12 m3/min, sand volume of 27 m3 and CO2 injection of 1500 m3. In 2017, this equipment system was used in waterless fracturing for six times, with a maximum proppant input of 23 m3. Both the liquid and sand supply processes are found stable, and the production gain after stimulation is considerable.

It is estimated that in tight reservoir, oil production brought by 1 unit volume of CO2 equals to that of 2.4 unit volume of water-based fracturing fluid. Providing that the average CO2 injection of waterless fracturing wells is 630 m3, a single well can save 1512 m3 water resource. This equipment system fully meets the requirement of fracturing in vertical and horizontal wells of unconventional resources, and can effectively support the further development of the waterless fracturing technology.
A Human-Computer Hybrid Approach to Offshore Field Development: Combining Virtual Reality Aided Design with Stochastic Optimization
Authors: Almedallah Mohammed , Walsh Stuart , Lau Tsan Hou
Published: October 2018

Offshore oil and gas field developments are capital-intensive projects that require extensive facilities to drill, produce and transport the hydrocarbon from the reservoir to the processing plant. Determining the site, number and size of these facilities are amongst the most important decisions impacting a project's success. Here, we present a novel strategy to assist in these decisions by combining a stochastic optimization routine with a Virtual Reality (VR) Aided Design. The model uses a discrete-network optimization algorithm that employs a Monte Carlo Markov chain to explore feasible configurations that minimize the development's investment. It integrates the optimization with a state-of-the-art VR environment to allow the engineer to both monitor the progress of the optimization and help guide the field development in real time.

We present results illustrating how the approach can be employed in field developments to connect well targets to processing facilities. The model determines the optimum location, size and number of offshore well-head platforms, tie-in facilities, well paths and pipeline routes. It incorporates critical technical considerations for the design of drilling paths (e.g. dog leg severity) and surface facilities (e.g. water depth). The model has been applied to real data from offshore field developments in the North Sea and the Gulf of Mexico. Results including the investment value and optimum configuration are shown and supplemented with graphics from the VR environment. The VR technology enables a novel approach to optimize the development. The immersive platform lets the user not only visualize the field, it is also capable of providing real-time interaction with the computer-generated design. This allows the integration of engineering intuition and experience to enhance the development and eliminate infeasible or unfavorable configurations.
Application of Novel Predictive Analytics for Data Allocation of Commingled Production in Smart Fields
Authors: Chia Mabel Pei , Yakup M Hamzi , Tamin Muhammad , Surin Nicholas Aloysius , Mazzlan Khairul Akmal , Rinadi M , Hassan A Azim
Published: October 2018

This paper details out the application of a predictive analysis tool to ‘S’ Field's commingled production, aiming to enhance production allocation and reservoir understanding without the need of well intervention and a reduced frequency of zonal rate tests and data acquisition.

Allocation of the production data to its respective reservoirs is performed via a novel Multi-Phase Allocation method (MPA), taking into account the water production trending evolution derived from relative permeability behavior of oil-water in each reservoir to compute flow rates for liquid phases over time. The precision of the derived rates is constrained by actual zonal rates tests through Inflow Control Valves (ICVs). This method will be cross referenced against ‘S’ Field's existing zonal rate calculation algorithm, utilizing input data from well tests results and real time pressure and temperature data.

The MPA method demonstrates improvement in the allocation of production data as compared to the conventional KH-methodology as MPA takes into account the water cut trending between reservoirs. Leveraging on ICVs to obtain actual zonal rate measurements, this greatly reduces the range of uncertainty in the allocation process. MPA derived production split ratios closely match the split ratios derived from the ‘S’ Field's existing zonal rate calculation algorithm, which utilizes input data from well tests results and real time pressure and temperature data from down hole gauges.

It is observed that the usage of actual measured zonal rate tests reduces the range of uncertainty of the MPA data.

A combination of novel multi-phase deliverability models coupled with smart field technologies such as intelligent completions and real-time surveillance and analysis tools will increase the accuracy of the back allocation of multi-phase production data in commingled reservoirs.
In-House Software Development for Gas Production Optimization: A South East Asia Perspective
Authors: Wongkamthong Chayut , Wongpattananukul Kongphop , Suranetinai Chaiyaporn , Vongsinudom Varoon , Ekkawong Peerapong
Published: October 2018

Several gas fields in South East Asia share some common traits among them, obviously on their geological features but also on their complex field operation. With a large number of small gas accumulations spreading across a large area with high degree of lateral compartmentalization, production from these fields are usually accomplished by hundreds of wells through multi-branches field networks. The scope of this paper is to present the challenging journey of the company's in-house innovative methodology which resulted in the development of a robust software to address the above challenges. The main objective of the software is to optimize field production under numerous constraints present in these fields.

With the target to optimize field production and enhance predictive capability, the company integrates the experiences from operating several fields and proposes an innovative approach to tackle these field management challenges. The resultant software optimizes and solves the network calculation by simplifying and formulating the production network into a system of linear equations, then applying optimization techniques as large-scale simplex and mixed-integer linear programming algorithms, to search for the best production scheme while taking user-selected objective function into consideration. The workflow was developed using MATLAB optimization toolbox to work in conjunction with a familiar Excel-formatted input. Moreover, with the incorporation of the Decline Curve Analysis (DCA), it is also applicable for generating long term production forecast. The tool was further combined with Production Data Management System (PDMS) to provide a more efficient automated workflow. It was used to maximize condensate production in Arthit field, where the main constraints are to capture the production loss from CO2 removal unit and to limit mercury concentration in sales condensate. While, in Zawtika field, the application exploits quadratic programing to minimize the sum of gas production rate square hence controlling wells to produce at optimal rate, mitigating sand production problem.

In this paper, successful implementation examples and benefits gained will be discussed. It ensures that the condensate production in Arthit field is kept at optimal level compared with about 91% efficiency when subjected to conventional practices while, in Zawtika, applying the workflow and operation resulted in dramatically lower sand production problem. For future forecast, a look-back study was performed to make sure that the method of calculating future potential is accurate. Not only does this new tool provided a more efficient way for the teams to manage their assets but, more importantly, it also helps to save costs by reducing man-hours through its rapid computation.
Systematic Approach in Extending Liquid Loaded Offshore Gas Wells Production in Natuna Sea with Partial and Full Wellbore Water Shut Off: Case Study and Method Selection
Authors: Praditya Yusuf Alfyan , Satiawarman Anugerah , Nurrahman Fahmi , Medianestrian Medianestrian , Rochaendy Risnawan
Published: October 2018

Wells which produce dry gas reservoirs usually have low bottomhole pressure. But in many instance liquid is associated with the produced gas, it can come from the liquid in reservoir or condensed production liquid. When more liquid is introduced into the wellbore, the pressure gradient along the wellbore is higher. The increased liquid fraction creates higher backpressure on the reservoir delivering gas. In high pressure gas reservoir the presence of liquid can occur in several degree of bubble and slug flow; in depleted gas reservoir the liquid can kill the well as the gas does not have enough transport energy to lift the liquid. At the point when the gas velocity is insufficient to carry out liquid, liquid will start to drop and accumulate in the bottomhole creating a restriction on the gas flow path, the phenomena is called liquid loading.

This paper presents success case studies from Premier Oil Indonesia in handling and reactivating four liquid loaded gas wells in Natuna Sea offshore operation. Wellbore configuration and facility limitations in offshore operation (e.g. maximum deck load capacity, water handling capacity and crane capacity) create more complexity of the method selection in comparison to onshore operation. There are many gas well deliquification methods available in the industry, but not in instance that each method is appropriate for all conditions. The case studies presented in this paper provide description of how Premier Oil Indonesia screened several available gas well deliquification methods in the industry and came up with the water shut off proposal as the best and most proper method for its wells. The understanding of liquid loading indication, liquid source identification and operational details of gas well deliquification methods are the most important factors to determine the most effective and cost efficient method to handle liquid loaded wells. This paper also presents a general guideline in selecting the best gas well deliquification method for some specific cases under several operational conditions for onshore and offshore operations.
Improved Sand Management Methodology Application in Mature Field
Authors: Tugimin M Azri , Kamat Dahlila , Baghdadi Faical , Gupta Anish , Mohammad Azili Ammar , Mohamed Hanafi Muhammad Mukrim , Meza David
Published: October 2018

Sand Monitoring workflow was introduced in R field to manage and minimize the risk that sand production poses to the production facility by monitoring the sand production and its resulting erosion rate, and raise alarm immediately when these conditions violates the allowable threshold. The workflow serves as an enabler to the sand management process that are put in place at the field. By leveraging the automation from IO and complement it with additional processes, we came up with a holistic approach that is used to minimize the risk to the production facility. The defined Sand Management methodology starts with the automated workflow processing. The workflow utilizes data from field sensors and processes them to conduct risk assessments, and some mathematical calculation that are based on proven correlations. Based on these processes, the workflow will generate output of sand production risk assessment, calculated erosion rate, estimated remaining pipe thickness as a result from the erosion rate and critical drawdown monitoring.

To complement the output from the workflow, additional processes that utilizes the outputs are introduced as part of the sand management process. Some of these additional processes are: Correlation calibration by comparing the estimated pipe thickness from the workflow against computerized radiography or unit thickness manual measurement.Conduct Sand Depositional modelling at the high-risk location identified from the workflow to optimize sand handling capacity and monitoring.Extend the monitoring by utilizing network modelling software to assess the erosional risk from interlink of pipelines between jackets.Choke health monitoring and estimation based on choke CV and modelling.

The sand monitoring workflow has increased personnel efficiency by automating repetitive and tedious work and give out the result in an easily interpreted manner. The automated alarm has been proven to be useful in proactively engaging operations to tackle the problematic matter. Production interruption related to sand production has been effectively reduced by 50% after the implementation of the new Sand Management methodology.

The introduction of the workflow into the new methodology uses marginal cost, but maximizes the return on existing asset through the realization of their production potential, as well as proving on how multidisciplinary integration and collaboration between operator and the service company can be successful in a mature field despite the risk associated.
A New Method to Predict FWL Based on Porous Plate Capillary Pressure and Resistivity Relationship
Authors: Tan Willy
Published: October 2018

The proposed method in this paper estimates FWL based on the relationship derived between resistivity, capillary pressure, water saturation and permeability. Since porous plate experiment provides simultaneous resistivity index (RI) and capillary pressure at identical saturation state, one can combine these two pieces of information (Pc-vs-Sw and RI-vs-Sw) and produce a new Pc/Rt-vs-Sw plot. Interestingly, Pc/Rt-vs-Sw exhibits an exponential behavior which can be described using an exponential function with fitting coefficient a, b, c and d. Once these fitting coefficients are obtained for each individual plug, they are correlated to petrophysical property such as permeability. After all the relationships are established on core plugs, the log-based capillary pressure (Pc, laboratory condition) can be estimated from the resistivity, water saturation and permeability logs. For application in oilfields, this laboratory condition Pc has to be converted to reservoir condition Pc. The reservoir condition Pc is interpreted as reservoir condition buoyancy pressure (Pb). We then subtract this reservoir condition Pb from the hydrocarbon pressure established from the formation tester. Finally, a water line with a known gradient (eg: 0.433 psi/ft) can be drawn across the predicted log-based buoyancy pressure. FWL is located at the intersection between this ‘pseudo’ water line and hydrocarbon line established from formation tester.
Waterflooding Heavy Oil Reservoirs with Horizontal Wells: Field Examples from Canada
Authors: Delamaide Eric
Published: October 2018

Very few papers describe waterflood projects in heavy oil reservoirs, and even less that involve the use of horizontal injectors and producers. A few years ago, Beliveau presented a review of waterfloods in viscous oil in several pools mostly in Canada and demonstrated that excellent results can be obtained in most cases, but he mostly focused on pools with vertical wells. The purpose of this paper is to present results of several heavy oil waterfloods in Canada that use horizontal producers and injectors.

The production performances of eight heavy oil pools where waterflood has been implemented using horizontal wells have been studied. The pools are thin and bottom water is present in some of them; oil viscosity ranges from a few hundred to a few thousand centipoises. The overall performances of each flood will be discussed and compared to other heavy oil pools where waterflood is implemented with vertical wells. In addition, more detailed analyses will be performed in some patterns to better evaluate the impact of bottom water, well length, spacing and other factors on the flood performances.

As could be expected, water breakthrough is generally fast, within a few months from the beginning of injection; but more surprisingly, Water Oil Ratio can often remain stable for long periods of time. Ultimate recovery is expected to vary from a few percents OOIP to over 20%OOIP. Similarly, to waterfloods with vertical wells, a large portion of the reserves can be recovered while producing at high Water Oil Ratio.

This paper will present results of several waterfloods in heavy oil reservoirs in Canada which use horizontal wells. There are very few such field cases in the literature thus the information provided will be of interest to engineers who are considering waterflood as a follow-up to primary production in heavy oil reservoirs developed with horizontal wells.
Sand Prediction for a Cost-Effective Marginal Green Field Development
Authors: Mohd Hatta Siti Aishah , Zawawi Irzee , Gupta Anish , Ahmad Nadzri M. Safwan , Salleh Nurfarah Izwana , Jeffry Suzanna Juyanty , Sharif Natasha Md , Ishak Izza Hashimah , Maoinser M. Azuwan
Published: October 2018

Field B is a marginal green field located offshore Sarawak, Malaysia with formation depth of less than 1000 meters. The compressional sonic transit time range is from 100 – 115 μs/ft, which immediately triggered the possibility of using active downhole sand control as this range is assumed to be unconsolidated. However, the rock mechanical strength characterization tests from sidewall core indicated contradictory result of a consolidated formation. Since the field is considered as a small field, the cost of the well especially on downhole sand control device need to be extensively optimized. Hence, sand prediction study for a small green field development using field and laboratory measurements was performed.

Several methodologies of sand prediction were utilized to evaluate the optimum sandface completion and sand control management for the field. Empirical and analytical sand prediction based on the well logs, sidewall cores analysis, and sand prediction software are employed to evaluate the likelihood of sand production and the optimum well completion design for the field development. The available data from appraisal wells of Field B is also calibrated to the nearby brown field, Field A that has been producing for more than 30 years.

This paper will discuss on the sand onset prediction results between full perforation versus oriented perforation, and pressure depletion impact on the sand production. The study shows that the formation is not prone to sand production especially in the early part of the production life with high reservoir pressure and low watercut. The expected Critical Drawdown Pressure (CDP) generated from different methods show large variation of sand onset pressure if the sandface is completed using full perforation. Oriented perforation tremendously expands the sand free drawdown limit. Based on the results of the study, expected reservoir pressure depletion and watercut, the completion of the wells adopted Oriented Perforation with no other downhole sand control equipment.

This paper is beneficial for petroleum and well completion engineers especially on sand prediction part of well completion design in development stage. This will assist in ensuring the field meets the EUR and bring forward economic value as well as well integrity assurance.
A Case Study on Drilling Complicated Infill Horizontal Wells in Low Cost Environment: Challenges in Well Construction and Its Successful Mitigations
Authors: Singh Ankit , Goyal Abhinav , Hiregoudar Ashita , Tomar Gaurav , Sharma Anurag , Katre Anurag , Doodraj Sunil , Vermani Sanjeev
Published: October 2018

This paper presents a case study of drilling of three horizontal wells, drilled as a part of fifteen wells onshore in-fill drilling campaign in a highly dense field, with 300+ wells in a span of 14 sq. km. The well design aspects, directional planning and implementation of innovative parameter monitoring tool for efficient drilling operation and accurate well placement is discussed in detail. Additionally, paper discusses in detail, re-engineering and limit extension of cold-stacked 1000 HP drilling rig to achieve the drilling objectives.

"Measure & Manage" approach was practiced at each and every stage while planning these wells to make them "drillable" utilizing the existing resources. To drill these complicated horizontal wells, a 1000 HP drilling rig which was in cold-stack condition was the only available option. The rig was made fit for successfully drilling these complicated horizontal wells by planning and optimizing the utilization of rig equipment viz. mud pump, rig tubulars, top drive etc. within its safe working & endurance limits. The well path was finalized after multiple iterations to ensure the well trajectory is free of collision threats from nearby drilled wells and also geological objective of draining the zone of high oil saturation is achieved hand in hand. Detailed Torque and Drag (T&D) and hydraulics model was prepared and analyzed for each operational step and every hole sections to identify the correct boundary line parameters for each operation. Based on these analyses bottom hole assembly (BHA) and bits were selected to deliver best possible ROP & directional control. All the drilling parameters critical to the operation were measured and monitored using"drilling parameters dashboard" to ensure that they are within the boundary limits as defined while planning the well. Friction factors were modelled, calibrated and measured on every trip to judge the hole condition for subsequent operations. Geo-steering was implemented while drilling the drain hole section of the wells for accurate well placement into the reservoir.

As a result of detailed step by step planning, accurate measurement and meticulous approach the three horizontal wells, which appeared practically undrillable with the available drilling rig & associated resources on first look, were drilled successfully. The actual time taken to drill these wells was within the planned time and within the allocated budget.
Risk Factors Affecting Delays in Upstream Natural Gas Mega-Projects: An Australian Perspective
Authors: Basak Munmun , Coffey Vaughan , Perrons Robert K.
Published: October 2018

The rapid expansion of the Australian gas industry has seen massive investment in mega-projects, but benefits from this have been impeded by the impact of severe project delays. Risks causing delays in upstream mega-projects are high, leading to frequent cost and schedule overruns. However, the absence of research concerning delays during this complex phase of mega-projects provides the opportunity to critically examine underlying challenges experienced by various project participants involved in upstream gas projects in Australia.

Data was gathered through an extensive literature review, interviews with industry experts, and a survey. A list of risk factors extracted from the literature was checked with industry experts for relevance in upstream mega-projects, and missing risks were added. The survey was circulated to a random sample of people working within the natural gas projects domain, including clients, consultants, and contractor organisations. Using Likert-style five-point scales, participants rated the frequency of occurrence and severity of each of the risks impacting delays.

A total of 70 risk factors were identified, which were then traced back to 10 risk sources that impact delays in upstream gas projects. The findings reveal that 72% of participants believe that the average delay in gas projects is between 10% and 30% in Australia. Moreover, 93% of participants mentioned that schedule slippage in the upstream phase causes severe challenges in attaining "first gas" and results in overall project delays. Based on the frequency of occurrence and severity indices, the magnitude of risk factors and sources was used to ascertain critical risks causing major delays. Kruskal-Wallis and Mann-Whitney U tests were applied to check the differences in perception of risk criticality influencing delays among the participants, who differed depending on work experience, job position, and the type of participants’ company. These tests indicated a good association in such perceptions. Key risk factors causing major delays included frequent change orders being issued by clients, unrealistic time schedules imposed on contracts, and poor organisational structures.

Risks in mega-projects cannot be eliminated completely. However, a more precise identification and prioritisation of risks causing major delays, along with differences in risk perceptions of various project parties, will provide an informed and broader perspective to industry practitioners and stakeholders in managing risks more effectively to reduce upstream gas project delays.
Structured Approach in Qualifying Cement Isolation Through the Use of Cementing Scorecard and Post-Job Execution Data
Authors: Heu Tieng Soon , Wee Anson , Combe Caroline , Mohd-Radzi Razif , Zhang Ting-Ting
Published: October 2018

Conventional ‘textbook’ primary cement job execution has always been associated with the combination of bumping top wiper plug, successful casing pressure test and/or no losses during the job. These criteria have been referenced by the general industry as positive indications and conveniently adopted as qualification for a successful cement job without considering other key parameters that contributes to proper cement isolation behind casing. In a deepwater development campaign offshore Malaysia, cement isolation behind the 9-5/8" production casing serves as critical barrier to ensure well integrity throughout the production lifecycle. To achieve this, the authors have deployed a structured approach focused on designing for success and optimizing a set of key performance indicators (KPIs) with pre- and post-drilled hole conditions. This paper outlines the approach based on the experience from the drilling campaign of nine oil producer wells.