bluuebunny/crossref_metadata_2025 huggingface dataset:
Modeling Two-Phase Flowback Data Using an Open Tank Model
Authors: Xu Y. , Fu Y. , Ezulike D. O. , Dehghanpour H. , Virues C. J.
Published: October 2015

In a previous paper (SPE 17163), a v-shape Gas-Water-Ratio (GWR) was observed and discussed from eight wells completed in the Horn River Basin, based on which the flowback data were divided into Early Gas Production (EGP) and Late Gas Production (LGP). The negative sloping GWR observed during EGP was assumed to be a ‘fracture cleanup’ period with negligible influx from the matrix system and a closed-tank model was developed for the fracture system to analyze flowback data. However, the effective fracture network is actually an open system which allows fluid influx from the surrounding matrix blocks. In this paper, we extend the previous model by considering the effect of gas influx during EGP.

Analyzing flowback data requires challenging mathematical procedures, which in most cases are still insufficient to capture the complexity of the two-phase flow in the fracture network. Material Balance Equation (MBE) is a simple but convincing tool in that it eliminates the assumptions lying in the flow equations. This paper seeks to use the MBE technique to analyze early-time two-phase flowback data in shale gas reservoirs. Diagnostic plots from field production data show an immediate gas breakthrough and a negative GWR trend at the beginning of flowback, which indicate the presence of initial gas in the fractures before opening the wells. Based on this observation, we develop a model to describe gas and water production during the early hours of flowback. The early-time two-phase production comes from an ‘effective fracture system’ initially saturated with gas and water. The model considers four drive mechanisms including gas expansion, water expansion, fracture closure and gas influx from matrix. Further, we propose a procedure to analyze field data using different forms of MBEs. It allows the estimation of the effective fracture volume which is difficult to measure in field cases. Finally, we demonstrate the application of the proposed material balance model by analyzing flowback data of one well completed in the Horn River Basin.
History-Matching and Forecasting Tight Gas Condensate and Oil Wells Using the Dynamic Drainage Area Concept
Authors: Clarkson C. R. , Qanbari F.
Published: October 2015

Recently, low-permeability (tight) gas condensate and oil reservoirs have been the focus of exploitation by operators in North America. Multi-fractured horizontal wells (MFHWs) producing from these reservoirs commonly exhibit long periods of transient flow during which two-phase flow of oil and gas initiates due to well flowing pressures dropping below saturation pressure. History-matching and forecasting of such wells can be rigorously performed using numerical simulation, but this approach requires significant data and time to setup. Analytical methods, while requiring less data and time to apply, have historically been developed only for single-phase flow scenarios. In this work, a novel and rigorous analytical method is developed for history-matching and forecasting MFHWs experiencing multi-phase flow during the transient and boundary-dominated flow periods.

The distance of investigation (DOI) concept has been used for many years in pressure transient analysis to estimate distances of reservoir boundaries to wells, amongst other applications. In the current work, the DOI concept is used to estimate dynamic drainage area (DDA) for the purpose of forecasting of tight gas condensate and oil wells – a linear flow geometry is assumed. During transient flow, the DDA is calculated at each timestep using the linear flow DOI formulation; a multi-phase version of the linear flow productivity index equation and material balance equations for gas and condensate/oil are solved iteratively for pressure, saturation, and fluid production rate. The productivity index equations for gas and oil utilize pseudopressure which is evaluated with saturation-pressure relationships derived from PVT data. For boundary-dominated flow, when the drainage area is static, the inflow equations are again coupled with material balance for both phases.

The new method is validated against numerical simulation, covering a wide range in fluid properties, and operating conditions. The new method matches simulation acceptably for all cases studied. Field examples of MFHWs are also analyzed to demonstrate the practical applicability of the approach. The three liquid-rich shale examples analyzed were also chosen to represent a wide-range in fluid properties. In all cases, acceptable history-matches are achieved.

The new analytical forecasting/history-matching procedure developed in this work provides a practical alternative to numerical simulation for tight gas condensate/oil experiencing two-phase flow during the transient flow period. The method, which does not rely on Laplace space solutions, is conceptually simple to understand, easy to implement, and avoids the inconvenience of Laplace space inversion.
Determining Well-to-Well Connectivity in Tight Reservoirs
Authors: Mirzayev Mammad , Riazi Naimeh , Cronkwright David , Jensen Jerry L. , Pedersen Per K.
Published: October 2015

Drilling and fracture stimulating horizontal wells in economically marginal fields, such as tight oil reservoirs, is a common practice. Estimating the connectivity between these wells (IWC) is important for the design and management of a field when waterflood recovery is applied. For example, IWC affects the determination of fracture conductivity and length and can help identify favorable locations for infill drilling and optimize injection rates.

Numerical simulators, such as streamline simulation need a geological model to determine IWC. Constructing the geological model, however, may take months. In this paper, we show how an alternative method, developed for and successfully applied in conventional reservoirs to determine IWC, can be modified to estimate tight formation IWC using solely production- and injection-rate fluctuations. The model is based on the Capacitance Model, or CM, and is modified to include a pseudo well (CM-PW).

The CM-PW is tested with various heterogeneous simulation cases and field data. The CM-PW can identify inter-well heterogeneities and differentiate them spatially. We observed that in some cases the CM-PW performs better than streamline simulation results while calculating production allocation factors. The CM-PW detects whether all the injected fluid volume goes to producers. The model accuracy is based on the match to production data and, for all simulation cases, the model accuracy R2 ≥ 0.83. The field application, from a tight oil waterflood in the Bakken Formation, shows that the CM-PW results agree with tracer test results and field reports showing fracture hits between wells. Seismic interpretations also strongly support the CM-PW evaluations.

The IWCs evaluated by the CM-PW during unsteady state flow periods provide key information to make a favorable decision at the early stage of water flooding in tight oil formations. Integrating the connectivity analysis, with tracer tests, seismic, and the geology enabled us to determine the reasons for the connectivity observed, identifying whether injected fluid flows through geological bodies or fractures between an injector-producer pair.
Application of Pressure-Monitoring Data in Land-Based Unconventionals
Authors: Marcuccio Suzi , Flygare James , Konopczynski Michael
Published: October 2015

The acquisition of accurate downhole pressure measurements from land-based unconventional wells can enable analysis of pressure data that can be used to help optimize and reduce the cost of fracture treatments and improve overall well productivity. The pressure data for the analysis are obtained from downhole electronic gauges in both the target well and in the surrounding observation/monitoring wells. The objective of this paper is to demonstrate the value monitoring this downhole pressure data can provide throughout the life of land-based unconventional wells. The paper also describes the selection of the equipment, the steps necessary for its successful installation, project commissioning, and acquisition of reliable data throughout the life of the well.

Historically, operators have experienced less-than-desirable success rates for long-term downhole pressure monitoring, especially in multizone, openhole, horizontal wells. This paper discusses how the success rate of these installations has been significantly improved by the implementation of a program with a well-defined series of steps that includes detailed planning (completing the well on paper exercise), onsite function testing of equipment prior to installation, and stringent attention to job execution detail. This program is based on the fact that adoption of the proper selection criteria for the application is critical to selection of the proper type of monitoring equipment and to the operational and economic success of these pressure-monitoring projects.
Production Excellence Opportunities Portfolio Management System: Key in Mature Field Rehabilitation
Authors: Ruslan M.
Published: October 2015

This integrated management system is design to efficiently manage and optimize the production excellence opportunities portfolio especially in mature field where higher risk presence technically and economically. Project management, LEAN process, lesson learnt and best practices were incorporated in developing the standardized workflow. The portfolio optimization model provides comprehensives technical and economical evaluation.

The technical success probability sub-model incorporates the technical KPIs and the project criticality index to generate project level probability. At this level, due to lack of local experience, the outcome can be either optimistic or pessimistic. To prevent this and recognizing the similar technology has been utilized elsewhere to solve similar problem, the industry track record can be combine with local perception via Bayes' Theorem to generate more realistic probability. The potential way forward is to incorporate the sub-model with case based reasoning and Bayes network for a more robust decision and evaluation.

The economic sub-model combined with project schedule incorporates probabilistic assumption to the benefit for each technology, hydrocarbon price, cost and time. The portfolio optimization risk-gain model incorporated both the forecast results from technical and economical sub-models to optimize the new technology portfolio. The model will run 1000 iterations to achieve the objective by maximizing the P50 NPV (net present value) of the project but within the predefined constrained and acceptable risk. The optimization results will be further undergo multidisciplinary peer review prior continuing the standardize workflow.

The management system is currently used in mature field project in North Sea to efficiently identify, manage, optimized the opportunities portfolio, and has demonstrated good execution and success cases.
Major Incidents Prevention and Sharing Lessons Learnt in Oil Field
Authors: Al-Shatti Ahmad , Al-Rakdan Abdulwahab , Al-Khaldy Ali
Published: October 2015

During the exploration and production of oil and gas resources in Kuwait Oil Company, a wide range of risks and dangers are present frequently, which have the potential to result in a major incident.

This paper describes a case study on sharing vital lesson leant from major incidents (work related/ Non-work related) that occurred in recent past. All these incident have thoroughly been investigated and intricate underlying causes and root causes of these incidents been identified. A lot of new lessons from these incidents were identified which are very vital for drilling industry to look upon and learn from these in order to avoid these learning from own experiences on the cost of loss of life/property. Various relevant corrective actions have been described in this paper in order to prevent the occurrence of such incidents in future.

The outcome from this paper is intended to improve the competency of the employees and increase their awareness of the sake of incidents prevention. Kuwait Oil Company has focused on reducing the probability of similar incidents occurring in the future by adopting generative culture in sharing lessons learnt among all employees and conducting various significant initiatives for all HSE aspects. Other Drilling Industry in the region may also be befitted by adopting the outcome of this presentation being in similar nature of work environment.
Factors Affecting Delay of Upstream Oil and Gas Development Projects in Indonesia: Case Study 2012 - 2013
Authors: Simanjuntak Josia T. , Mahendrawan Anggono
Published: October 2015

It is widely accepted that a project is successful when it is finished on time but unfortunately, due to many reasons, in Indonesia, a large number of upstream oil and gas projects failed to meet their original contract time. The success of the delivery of upstream oil and gas projects in particular becomes pivotal as oil and gas production steadily declines each year, and Indonesia's economy and revenue are highly dependent on the upstream oil and gas sector. For example in 2012, 15 projects with the combined maximum throughput capacity of 1,062 MMscfd and 23,060 bopd were initially expected to go on stream. However due to a number of reasons, 12 out of 15 projects were delivered with the combined maximum capacity throughput of 430 MMscfd and 5,600 bopd only.

As mandated by the government, the Special Task Force for Upstream Oil and Gas Business Activities in the Republic of Indonesia (known as SKK Migas) is responsible for developing upstream oil and gas projects as part of its main function in terms of maximizing national oil and gas production. This paper presents our experience, as a government agency, in managing all upstream oil and gas development projects in Indonesia. This paper also reviews the major project and construction management challenges experienced in Indonesia.

All information and data were acquired and gathered throughout a series of intensive monitoring with all Production Sharing Contractors in Indonesia: meetings, discussions, site visits and written reports. All this information was further analyzed and categorized into several main factors that affect the delay of oil and gas development projects based on original Plan of Development and Engineering, Procurement, Construction and Installation contracts. The findings show that the main critical factors that cause delays in Indonesia are contractor performance, logistics, government approval and permit, societal, environmental and commercial issues.

In addition, this paper also explores and provides some recommendations to reduce the impact of delays on oil and gas projects in Indonesia.
Production Optimisation With Zero Gas Venting Through Multiphase Booster Pump and Well Selection
Authors: Maryunani S. , Ranggun R. A. , Johari E. , Ting P. E. , Raislar G. M. , Gajet D. A.
Published: October 2015

TM Platform is a mature oil producing facility located in East Malaysia. It has been producing since 1979. Being an aging field, production with higher gas/oil ratio (GOR) and wider pressure range at remote platform which is flowing into single pipeline to the processing platform, encountered bottlenecking which restricts the flow from lower pressure wells. This paper outlines the concept of technology and operational intervention to minimise surface bottlenecking at one of TM remote platforms, TM-X.

As an effort to boost production from lower pressure (LP) wells at TM-X, a multiphase booster pump (MBP) was commissioned. It was designed to create low suction pressure to enable maximum drawdown from the wells. Selected LP wells were diverted into a dedicated line header, flown into the multiphase pump, and discharged into the main line header to commingle with the higher pressure (HP) wells. Further optimisation of pump capacity was achieved by lowering down the gas throughput. This is done by using routine well testing to select optimum well candidates with lower totat output gas (formation gas plus injected gas) and flowing tubing head pressure (FTHP).

Currently, MBP with optimum well selection is enabling oil gain of approximately 1500–2000 BOPD. Multiphase booster pumps (MBP) is a gas engine driven, plunger type pump. Some of the low FTHP wells which were unable to flow because of backpressure from the higher pressure wells in the pipeline are now able to flow via MBP. MBP is not a common equipment and has never been installed at any offshore location in Malaysia before. Therefore, operating and maintaining it was challenging. Operational intervention such as increasing frontline spares, improving operator competency, and daily parameter logging played a crucial role in ensuring the optimum performance of MBP.

This booster pump and optimisation process can be further replicated at other oil platforms to increase the production, especially in a remote platform which wells have higher GOR or formation gas rate and lower FTHP, but no dedicated pipeline and infrastructure to flow the crude according to its pressure setting range for each higher and lower pressure wells, respectively.

MBP with its nature as a multiphase pump is suitable for remote platform with unmanned philosophy at which continuous local gas venting or emission shall be kept to minimum. With complete unit shutdown system tied-in to TM-X shutdown system, and electronic Unit Control Panel (UCP) enables recording of trip history for ease of troubleshooting and eliminate unsafe conditions, MBP is applicable at unmanned remote platforms with minimum daily man-hour visit.
Integration of the Pressure Depletion in Static Model to Improve Resources Forecast for Future Development of Deltaic Mature Peciko Field
Authors: Roussel S. , Akbar E. , Herawati S. , Muhazir Y. , Herwin H. , Schulbaum L.
Published: October 2015

Peciko is a giant gas field located in offshore Mahakam delta, Indonesia. Hydrocarbons are accumulated in multi-layer reservoirs corresponding to several disconnected stacked distal mouth bars and occasional channels. The trap consists of a 4-way dip closure. The field is producing since 1999 and the reservoirs are depleted with strong variation from one layer to another. Building dynamic reservoir models of a mature field with ~90 layers in production and roughly 300 Geological Pressure Units (GPU), which are then updated regularly taking into account data of newly drilled wells, is very complex and time consuming. However, locating and quantifying the depletion are keys to identify the under-developed areas and to launch additional infill wells. In order to overcome the challenges, to save time and gain reactivity, an innovative workflow has been developed. This workflow encompasses dynamic data and synthesis from production history and allocation, and P/z analysis for pressure depletion modeling, all integrated in the static model. This static model then becomes the tool to support the collaborative works of geologists and reservoir engineers.

It is observed that the pressure depletion is function of net sand stacking, stratigraphical units and gas production which is related to the well spacing. The depletion modeling is based on the pressures measured at wells and actualized to certain time then distributed for each layer in the static model using the net pay as geological constraint. Depletion decline rate is derived from formation pressure measurements & PLT data per layer. By predicting the current pressure, present hydrocarbon-in-place can be estimated and mapped. Gas material balance (P/z analysis) at well level is analyzed in association with well intervention activity (perforation, zone change, and water shut off) to quantify the remaining connected gas-in-place. Allocation layer by layer is then performed based on the production gain after intervention and reservoir properties / pressure or reservoir contribution from PLT results. The results are integrated in the static model through an iterative process and help to identify un-drained areas, thus revealing incremental resources for the future wells. The final result of this method is a remaining hydrocarbon-in-place stacked map used to define new development wells and their associated resources in Peciko field.

The innovative automatic workflow involved an integration of many data and analysis from more than 100 wells with more than 90 producing layers that can be up-dated easily in reasonable time. The method is user friendly, straightforward and applicable to other fields.
A Case Study of a Coiled Tubing Gas Lift Pilot Project in the Cooper Basin, South Australia
Authors: Vasquez Rivas F. R. , Bon J.
Published: October 2015

A Coiled Tubing Gas Lift (CTGL) pilot project was implemented in a light, volatile oil reservoir of the Cooper Basin, South Australia. This paper presents the full lifecycle of the project, from concept initiation to execution and first measured field data.

High pressure lift gas was injected through ¾" coiled tubing, installed inside existing tubing strings and hung from the wellhead. Implementing gas lift in this manner avoided recompletion of the wells and minimised costs. A trial on two wells at a neighboring field was executed in mid 2011 this trial was a world first for ¾" coiled tubing deployed gas lift.
Formation Testing and Evaluation in Challenging Wellbore Conditions: An East Asia Case Study
Authors: Kyi K. , Haddad S. , Ooi A. , Chouya S.
Published: October 2015

Evaluating hydrocarbon columns, reservoir fluid types, contacts and productivity has been challenging in East Asia, especially when open hole well challenges are encountered. Initial openhole attempts are at times unsuccessful in proving significant hydrocarbon potential mainly due to severe losses, high differential pressure or bad hole conditions. The need for a new formation evaluation strategy became necessary to secure critically needed data for the prospect evaluation. The objectives, apart from establishing the presence of hydrocarbon column, is to optimise well drilling execution in a safe and timely manner. In addition to losses challenge, wells encounter hole stability issues with shale being overpressured and potential presence of H2S, whereby its level need to be determined onsite for completion strategy.

To meet the objectives of these wells, an alternative formation testing and sampling strategy has been adapted. The reservoir fluid evaluation was postponed until the open hole was cased. The formation evaluation with Wireline Formation Tester (WFT) was performed in two stages, the first stage was to confirm the presence of cement isolation at the hydrocarbon intervals, and the 2nd stage was to perforate intervals at the zones of interest to confirm the hydrocarbon columns by downhole fluid analysis and sampling.

This case study will discuss reservoir rock and fluid evaluation in cased hole with WFT. Reservoirs of interests are successfully evaluated and representative samples are successfully acquired without any operational issues. Recommended evaluation strategy and best practice supported by field data will also be presented in this paper
Rigorous Safeguard for Wash Tank Roof Demolition
Authors: Kayely Boris Victor , Wiryawan Sony Aria
Published: October 2015

Wash Tank T-03 in Bangko Gathering Station had been operated for 40 years. Its capacity was 56,000 bbls with 100 ft diameter and 40 ft height. Based on last inspection report the roof was corroded and perforated. Prior to demolition work it was found that the condition of the roof was worse than expected.

As preparation for demolition work, the tank must be cleaned from any hydrocarbon. Considering the roof condition, it was forbidden to enter the tank for cleaning activity. Hence cleaning activity could only be done from outside of the tank (by using man holes). By cleaning from outside of the tank, the jetting pressure of cleaning equipment was not enough to clean upper part of shell and roof. Therefore demolition work by using cutting torch (hot work) was not allowed to prevent any fire incident.

Project team looked for other alternatives to demolish the tank such as by using excavator, water jet cut, and a self-propelled pipe cutter. By considering the availability, applicability, cost, existing condition, and space needed, it was decided that hot work was still the best method. Mitigations were needed to eliminate risks due to hot work. Blower and gas detector with prove were installed to eliminate fire risk. Upper part of shell and roof was cleaned by utilizing fire hydrant with modified hose.

This paper will discuss Wash Tank T-03 roof demolition since it was the critical part. The roof demolition was divided into three main steps: load test on roof, horizontal life line & pipe post anchor installation, and roof demolition.

The load test was conducted to ensure that a worker might safely work on the roof. Horizontal life lines were installed as safeguard for workers while working on the roof. A rigorous safeguard preparation was done including the important considerations for horizontal life line design like dynamic load, free fall distance, forces on the worker, fall clearance, and compatibility of fall arrest equipment. These were analyzed in accordance with existing international standards (ANSI/ASSE) and thoroughly discussed among engineering and construction team to capture all potential risks that might happen during roof demolition work. Even though the safeguard (life line) had already been installed, there was also special method to demolish the roof to minimize the risks.

Wash Tank T-03 had been safely demolished with zero incident. It was demolished in 5 (five) weeks with 60% time for roof demolition. But the main part was the rigorous preparation of demolition work, which took more than 2 (two) months preparation work to ensure that all potential risks were minimized and mitigated.
Refracturing Strategy for Sevensprings Oilfield in China Based on Geological and Engineering Characteristics
Authors: Ren Jichuan , Guo Jianchun , Deng Yan , Zhang Lihui , Lin Hai
Published: October 2015

Sevensprings oilfield is one of the oldest mature-flood fields with target stratum between 1000 and 1200m TVD in China with Strong permeability heterogeneity within the range of 0.01-50mD. Most of its wells have been fractured. But for now, the fractured wells have lost their power to maintain productivity. Early analyses show the wells have gained different production dynamics and the stress field around bottom hole was unclear after nearly 20 years water-flooding. Without a proper refracturing strategy, it still could not awake the wells properly.

This paper presents a novel method to determine the refracturing strategy and the priorities of the candidate wells by comprehensive analysis, which considers reservoir properties, remaining oil distributions and induced stress fields. Application shows this method is effective and it can provide a reference for the analogous reservoirs to develop refracturing strategy. First we found out the basic situation of remaining oil and reasons for low-yielding of different wells under various fracture orientation and stratigraphic features through simulation. Combined with these two factors, we can divide the wells into different types which represented by residual oil distribution and location characteristics. After this, we obtained the induced stress field through marching the Waterflooding history. Through analyzing the hydraulic fracture steering angle and steering range, we can figure out the feasibility of steering fracturing to each well type. At last, we made a productivity simulation for each well type with corresponding feature models and fracture steering possibility. Based on this, we can develop the suitable refracturing strategy for every well type and gain the priorities according to the simulated productivity increment.

The novel method established in this paper has been effectively applied in Sevensprings oilfield. Before this, there were more than ten well had been refractured, the average productivity growth rate was 34%, and some wells came to capacity drop because of incorrect treatment. Based on this method, we chose several candidates from more than 100 wells prepared to be refractured. And three of them have already been processed. All of them achieved preferable stimulation response. 3-3 shows an increasing fold of 3.85 from 2.57 t /d to 7.64 t /d. Shen-27 shows a daily production increase of nearly three times from 2.57 t /d to 7.64 t /d. Nowadays, larger-scale application was ongoing

Application shows this new method to determine refracturing strategy and well stimulation priority is effectively. And it can provide a reference for the analogous reservoirs to improve their re-stimulation response.
Modeling of CO2 Injection Considering Multi-Component Transport and Geomechanical Effect in Shale Gas Reservoirs
Authors: Kim T. H. , Park S. S. , Lee K. S.
Published: October 2015

Although several researches have been conducted for CO2 injection in shale gas reservoirs, there is definite lack of study that concentrates on the multi-component transport and geomechanical effect. This paper presents shale gas model for CO2 injection considering dissolution, molecular diffusion and stress-dependent permeability as well as multi-component adsorption. Based on information of Barnett shale reservoir, a simulation model is constructed for CO2 flooding. Extended Langmuir isotherm is used to simulate the competitive sorption among the molecules involved. Gas solubility is represented by Henry's law. Co- and counter-diffusive transportsare depicted by Sigmund correlation. Stress-dependent permeability in shale reservoir is considered by exponential correlation with the linear-elastic constitutive model. In the proposed model, the mechanisms and parameters which could influence on CO2 injection are studied. A series of reservoir simulations based on these effects are performed to study effective injection of CO2.

Mechanisms of CO2 injection in shale gas reservoir contribute to both enhanced CH4 recovery and storage of CO2. Desorption of CH4 in the model with the multi-component adsorption is activated by competitive sorption with the CO2 which is preferentially adsorbed over CH4 with a ratio up to 5:1. Molecular diffusion enables CO2 to displace CH4 in ultra-low matrix permeability condition. The model with molecular diffusion presents wide spread CO2 in the reservoir compared with the model not considering molecular diffusion. Because of ultra-low permeability of shale reservoir, effect of diffusion is higher than conventional reservoirs so that it should be considered in the CO2 injection model of shale reservoir. CO2 injection supports the reservoir pressure so that effect of stress-dependent permeability is mitigated compared with primary recovery model. In this model, CO2 injection improves shale gas recovery about 12%. The CO2 injected in the reservoir exists as a super-critical phase, adsorption trapping, and dissolution trapping of 45.8, 46.5, and 3.6%, respectively. According to reservoir and fracture parameters, amount of each state would be changed. The sensitivity analysis for either enhanced CH4 recovery or CO2 storage is conducted to investigate the critical parameters that control these CO2-EGR process and CO2 storage, respectively.

This work presents study for mechanisms of CO2 injection in shale gas reservoir taking account of multi-component adsorption, dissolution, molecular diffusion, and geomechanical effect and sensitivity analysis for uncertain parameters of the shale reservoir. The investigation is important for better understanding and design of CO2 injection in order to enhance CH4 recovery and CO2 storage.
An Innovative Algorithm to Detect Washout in Wellbore From Large-Scale Measured Caliper Data
Authors: Xie Liangjun , Chaudhary Saleem , Chen Zhongming
Published: October 2015

Detecting washouts (short, enlarged hole segments) is critical for job design computations in drilling and completion. However, the large-scale raw data from a six-arm caliper can have hundreds of thousands of measurements. This means manually determiningwellbore geometry and washouts from the raw data can be time-consuming and inconsistent. The industry needs an algorithm that can detect washouts effectively and consistently, and reduce data pointswhile preserving the fundamental characteristics of the data.

In this paper, we introduce a novel approach to detect washouts with significantly reduced data points from large-scale multi-arm caliper data. The proposed algorithm employs a two-loop data points reduction technique modified from the adaptive piecewise constant algorithm (APCA). In the first loop, the raw data is reduced to an intermediate number of segments by APCA, keeping the main peaks. A new data set is then reconstructed by replacing the values in the raw data with the calculated constants, and the data isthen processed by APCA to the required number of segments. Finally hole-size and washout are calculated with equivalent volume for each segment.

Data from borehole caliper logs have been processed by the proposed algorithm to reduce data points while keeping significant washouts. Comparisons were made by running APCA with both logged field data and simulated data. Our approach detected more washouts from fluctuated data than APCA with the specified number of segments. Applications with abnormal caliper data with unevenly distributed depth intervals also illustrate the effectiveness, androbustnessof the algorithm, while the original APCA fails to determine washouts in those cases. As a data mining method for similarity search for time series, the advantage of the proposed algorithm is that it can preserve peaks while reducing data. This new algorithm could also be applied in realtime monitoring.
The Wellbore Temperature Test and Simulation Analysis for Liquid Carbon Dioxide Fracturing Management
Authors: LV Xinrun , ZHANG Shicheng , YU Baihui , HOU Tengfei , ZHONG Ziyao , MENG Siwei , ZHANG Jin
Published: October 2015

Since physical parameters of CO2 are affected heavily by temperature and pressure, including density, specific heat capacity, thermal conductivity and viscosity, the calculation of wellbore temperature distributions during CO2 fracturing is different from hydraulic fracturing, in which those physical parameters are regarded as constants. In this paper we consider those physical parameters as variables in order to get more precise distributions of wellbore temperature during CO2 fracturing management.

A wellbore temperature distribution model during CO2 fracturing process is established in this paper. The math model is based on the energy balance equation and the momentum balance equation and solved by finite difference method. In the calculating process, we considered the effects of temperature and pressure on physical parameters of CO2. Span-Wagner model and Vesovic model are used to calculate those parameters including density, specific heat capacity, thermal conductivity and viscosity. MATLAB is used here to implement those algorithms.

Data of H79-31-45 well, a liquid CO2 fracturing well in Ji Lin-Field, is used to compare the calculated temperature with the measured data. This well use 0°C liquid CO2 as fracturing fluid to fracture the formation in depth of 1600 meters. The result shows that in the depth of 1000m and 1600m where the detectors are located, the relative errors between calculated data and measured data are less than 2% both at the beginning and the ending of the management. And as the injection time increases, the temperature of the wellbore has a significant decline, which illustrates very good agreement with result of the calculation. It indicates the precision of the simulation satisfies engineering requirement.

In general, since the established model has a high accuracy, sensitivity analysis can be undertaken to analyze the effects of different parameters like the injection rate and injection time on wellbore temperature and the results can provide insights for designing fracturing schemes.
Integration of Pressure Transient Analysis in Reservoir Characterization: A Case Study
Authors: Pinillos Carlos , Rong Yeo Chuo
Published: October 2015

Development of computer processing capability has helped nowadays to develop tools that are not only able to interpret a single Build-up or Drawdown but instead the whole pressure history acquired during welltest or the whole life of the well (when Permanent Down-Hole Gauges, PDHG, are available) by using either analytical solutions or numerical simulation techniques.

The use of recorded bottom-hole pressure during welltests to conduct Pressure Transient Analysis (PTA) should not be limited to classical approach of determining permeability and skin parameters. Moreover, when PTA is used in combination with classic Reservoir Engineering tools such as Material Balance and Rate Transient Analysis (RTA), then it can be very useful in Reservoir Characterization, Reconciliation of Initial in Place Volume obtained from different techniques and Identification of main Drive Reservoir Mechanism.

This paper describes the successful implementation of the aforementioned Pressure Transient Analysis applications in a Gas Field where the main uncertainties identified during the Field Development Plan (FDP) stage were: 1) Initial in Place Volumes, mainly as result of uncertainty of the Gas Water Contact (GWC) depth in the deeper reservoirs, 2) Connectivity between blocks, due to a fault presence and 3) Aquifer pressure support.

A deviation of historical pressure behavior from the Field Development Plan estimates was observed, which resulted in: a) Revisit of the assumptions made in the FDP and b) Re-evaluation of the Gas Initial In-Place Volumes (GIIP). The Integration of PTA, Material Balance and RTA together with the incorporation of 3–4 years of production and pressure history has proved to be a good practice to understand and characterize the reservoir allowing different methods (Volumetric, Material Balance, Rate Transient Analysis) to converge to a similar GIIP estimates.
Numerical Computer Modelling and an Innovative Spacer-Cement Train Results in Successful Zonal Isolation in Critical Well Offshore Australia with Minimal Casing Centralisation
Authors: Higgins M. C. , Nolan T. J. , Brandl A. , Bottiglieri A. , Jha L. K.
Published: October 2015

Challenging wellbore conditions in an offshore well in the Northern Territory, Australia led an Operator and Cementing Service Company to pursue a sophisticated approach to achieve zonal isolation on the critical 9–5/8-in. casing cement job. Some of the specific well challenges prior to and during the cementing operations included high bottomhole temperatures of 135°C at 3,724 m, lost circulation, low fracture gradients, and over-pressured source rock (gas). In particular wellbore instability due to tectonic stresses made it difficult to run casings to bottom, so centralizers were used only on the shoe track. The potentially increased casing eccentricity was a major concern during the cement job, risking channeling and resulting in insufficient zonal isolation.

Consequently, a comprehensive study focused on enhanced mud removal and cement placement to compensate the lack of proper pipe centralization and pipe movement during the job. Mud displacement and slurry placement efficiency were investigated as functions of important spacer and slurry design features as well as the given wellbore parameters (such as fluid density and friction hierarchies, gel strength, pump rates, fluid expansion and buoyancy, eccentricity, and temperatures) using computational modelling. The simulations and findings enabled optimization of fluid designs with the corresponding job execution increasing the success for zonal isolation. Proper pre-job planning, cementing program simulations, fluid lab tests, and reliable job execution were performed to achieve zonal isolation for the overall integrity of sidetracked wellbore section. Post-job analyses of the cement jobs, lab test results, pressure tests, and azimuthal ultrasonic cement bond log results were evaluated concluding sufficient cement coverage along the desired annuli, meeting the operator's requirements to demonstrate zonal isolation. This paper reviews the job performance and lessons-learned from the 9–5/8-in. casing cement job on this well. The findings contain useful cementing guidelines for critical well scenarios where optimum pipe centralization and movement are not feasible.
A Bio-Inspired Vibration Energy Harvester for Downhole Electrical Tools
Authors: Qinghai Yang , Xiaohan Pei , Cheng Hou , Gang Tang , Jingquan Liu
Published: October 2015

At present, most of the downhole electrical devices use disposable batteries or rechargeable batteries as power supplies. When the disposable batteries run out, the downhole devices have to be fished up to replace the batteries. For those tools with rechargeable batteries, chargers should be put into the downhole position close to the tools to recharge the batteries. The operations are very tedious and the normal production is interrupted. Inspired by discharging characteristic of electrophorus electricus, this paper proposes a vibration energy harvester, aiming to provide a long term power supply for downhole tools. The harvester mainly consists of bluff body, piezoelectric energy transducer, the size of designed piezoelectric beam is 52mm * 7mm * 0.82mm (Length * Width * Thickness), and a proof mass. The bluff body is cylinder and installed in front of the harvester, facing the flowing fluid. It destroys the steady flow and makes the piezoelectric energy transducer vibrating. Due to the piezoelectric effect, the vibrating of the energy transducer regularly generates electric energy. The electric energy rectified by voltage conversion circuit can be used to power the controlling system and the driving unit, or to recharge the rechargeable batteries of downhole tools. Under the laboratory condition of water flow velocity of 0.81 m/s and the Reynolds Number Re is 20000, the output peak-peak voltage of the piezoelectric energy harvester is around 44 V, which means it can directly provide the energy for rechargeable battery. This results show that the harvester can potentially offer an intriguing alternative for harvesting ambient energy from flow and provides a new method for long-term energy supply for downhole electrical tools. Futere piezoelectric energy harvester may use more efficient piezoelectric transducer and this device must be optimized to make the piezoelectric energy harvester could have a higher harvesting power.
A Two-Phase flow Model To Predict Liquid Holdup and Pressure Gradient of Horizontal well
Authors: Xu Darong , Li Xiangfang , Li Yuansheng , Teng Sainan
Published: October 2015

Gas-liquid two phase flow occurs extensively in petroleum industry. In gas-liquid two-phase flow, droplet entrainment in the gas phase and dispersed droplet adheres to the tube surface was usually observed in experiments; when gas velocity is larger than the critical velocity for entrainment.

Based on this new information, a new model is prosed to predict the liquid hold up and pressure gradient in stratified and annular flow, which could be considered the correction of Fan's model. The proposed closure relationships include the viscosity and density of the gas mixture weighted by gas and entrained droplet volume; the gas mixture-wall friction factor weighted by gas-wall friction and entrained droplet-wall friction; the increased flow rate of gas mixture and the decreased flow rate of liquid due to droplet entrainment. Then apply these new relationships into the momentum equation of gas mixture and calculation of interfacial-friction Factor, then liquid holdup and pressure gradient are solved through iterative calculation.

Then, the basic parameters of the proposed model were adjusted to agree with the stratified flow laboratory data from Meng and Fan's experiments. And the predictions of holdup and gradient are agreed well with that of laboratory data. What's more, the predictions are more accurately than Fan model when there have existed droplet entrainment.
Real-Time Surface and Downhole Measurements and Analysis for Optimizing Production
Authors: Gonzalez L. E. , Chokshi R. N. , Lane W. C.
Published: October 2015

Permanent surface and downhole measurement technologies have advanced considerably in terms of availability, reliability, performance and costs, and are increasingly deployed for real-time monitoring of wells and equipment. Permanent downhole sensors are used to measure pressure, temperature, flow rates, fluid phases and to reflect operating conditions in wellbores. Surface sensor systems provide real-time measurements of pressure, temperature, fluid phases and flow rates that need to be integrated for analysis. The resulting large volume of data has created challenges in data management, evaluation and analysis. It is important that production analysts have access to workflows and tools that provide real-time efficient and effective visualization and analysis. The optimal approach is to perform the visualization and analysis of data in real time, or near real time, to provide analysts with actionable information for timely and accurate decision making.

Permanent downhole gauges are used for monitoring reservoir drainage, injection efficiency, well-completion hardware performance, and downhole pump performance. Some of the resulting benefits include reduced operational costs, improved safety, and properly monitored well integrity. Several onshore and offshore case studies are discussed to demonstrate application of real-time measurements coupled with visualization and analysis techniques to also achieve improved artificial lift performance, reduced operating costs, and manage production. The value of the information obtained from downhole permanent gauges and surface measurements are justified as evidenced by the growing number of operators relying on real-time permanent gauges.

This paper reviews technologies that are used to monitor and manage equipment and production in oil and gas wells. It explains that the realized value of permanent monitoring depends on an efficient workflow for collection, evaluation, and analysis.
Nanofluid Alternating Gas for Tight Oil Exploitation
Authors: Zhang K. , Li Y. , Hong A. , Wu K. , Jing G. , Torsæter O. , Chen S. , Chen Z.
Published: October 2015

Over past decades, technology innovation in exploiting unconventional resources has become increasingly important. Associated with technologies applied in shale gas development, exploiting tight oil resources comes into a new stage. Primary recovery in tight oil reservoirs remains low even produced with massively hydraulically fractured horizontal wells.

Waterflooding is applicable over a wide range of reservoir conditions but its recovery is not high enough. In addition, gas flooding suffers from channeling problems with existence of highly permeable channels. A water alternating gas (WAG) process seems a good method to recovery tight oil.

Recent breakthrough in nanotechnology provides a promising technique in the oil and gas industry. Nanoparticles have a very high surface-volume ratio, easily moving into tight formation without external forces. Nanoparticles additive does not raise weight of an injection fluid, associated with wettability alteration and interfacial tension reduction, and can be an excellent solution in improving recovery in tight oil reservoirs.

This paper demonstrates the merits of nanofluids; concentration of 0.05wt% nanofluid gives the best performance in a core flooding test. Simulations of nanoparticles additive in a WAG process are run by Eclipse and CMG in various cases. As the degree of wettability alteration and permeability reduction highly depends on concentration of nanoparticles underground, a tracer is applied in the simulations to confirm the locations of nanoparticels underground and its concentration, and it shows that nanoparticles mainly stay around injection wells and high permeable zones. Simulation results show that a nanofluid alternating gas (NAG) process has a great potential in improving WAG performance, and it performs better with existence of natural fractures.