Chen, Zhiming (The University of Petroleum at Beijing) | Liao, Xinwei (The University of Petroleum at Beijing) | Zang, Jiali (Shanghai Petroleum Co., LTD) | Zhao, Xiaoliang (The University of Petroleum at Beijing) | Peng, Kewen (The University of Petroleum at Beijing) | Wang, Shaoping (Petro China Changqing Oilfield Co.) | Yu, Wei (Texas A&M University)
Treatments of stimulated reservoir volume (SRV) have been the most effective techniques to enhance well productivity in unconventional plays, like tight-oil reservoirs. Unlike conventional reservoirs, the work in unconventional plays needs to focus on the SRV scale rather than field scale, which requires an integration of many techniques to properly evaluate the SRV properties. Unfortunately, there still lacks of a comprehensive integration of seismic, models, and data for SRV, although much work has been done for fracturing estimations and performance predictions of wells with SRV. To narrow the gap, this paper presents a comprehensive seismic-forecast workflow for tight-oil reservoir development on the SRV scale. The workflow is an integration of microseismic data, well testing interpretation, rate normalized pressure (RNP) interpretation, and numerical production history match. Its contents are described as the following steps: (1) introducing the technique of microseismic monitoring (MSM) and proposing a corresponding simplified SRV model, (2) developing and verifying its well-testing model with boundary element method (BEM), integral method, and superposition principle, (3) discussing the rate normalized pressure (RNP) model of SRV, (4) building a numerical SRV model, and (5) demonstrating the workflow by a field case from Junggar Basin. This paper paves a good way to evaluate well performance and improve future completions in tight-oil reservoirs.
Applications of Nanotechnology are growing significantly in the petroleum industry such as oil recovery, and well stimulation. In aqueous media, fumed silica nanoparticles aggregate if there is sufficient attractive energy between nanoparticles. Aggregate size distribution evolves as aggregation continues, and once it spans the space, it forms a gel. The objective of this study is to study evolution of nanoparticle size distribution during transport in porous media, including the aggregation, deposition, straining and initiation of gelation. Population Balance equation (PBE) was used to model the growth of aggregates and the interaction between aggregates and porous media. Quadrature method of moments (QMOM) was used to convert the PBE with continuous distribution of nanoparticle size into moment transport equations for efficient computation. The closure problem for moment transport equation was resolved using Gaussian Quadrature that requires estimation of roots orthogonal polynomials. Wheeler algorithm was used for calculation of the coefficients of the recursive formula of the orthogonal polynomials. Finite volume method was used for discretization of mass transport equations, continuity equation and Darcy law. Changes in nanoparticle size and shape due to inter–particle interactions (i.e., aggregation) can significantly affect particle mobility and retention in porous media. To date, however, few modeling studies have considered the coupling of transport and particle aggregation processes. Model sensitivity analysis explained the influence of particle concentration, and interstitial velocity gradient on particle–particle, and, consequently, particle–collector interactions. Model simulations demonstrate that, when environmental conditions can promote inter–particle interactions, neglecting aggregation effects can lead to over-estimation of nanoparticle mobility. Results also suggest that the extent to which higher order inter–particle collisions influence aggregation kinetics will increase with the volume fraction of primary particles. The model shows that when nanoparticles dispersions are injected into free media like large pores or fractures that the effect of filtration is negligible, the gelation can be achieved but after longer time compared to the batch experiments. However, when including the effect of filtration, the viscosity of the does not increase due to exclusion of larger aggregates once they are formed. This prevents the growth of the gel network. The model developed in this work accurately captures aggregation and initiation of gelation of silica in porous media. This work demonstrates the potential importance of time-dependent aggregation processes on nanoparticle mobility and provides a numerical model capable of capturing/describing these interactions in water-saturated porous media. This modeling study attempts to answer the critical questions pertaining the coupling of aggregation and in situ gelation on the nanoparticles transport in porous media.
Centrifugal Pumps and Centrifugal Compressorsare classified as driven equipment which are widely used in the oil and gas industry. They are primarily used to boost the operating pressure and transfer liquid and gas respectively in a safe and reliable manner. Process containment is one of technical integrity and safety barrier classified under Safety Critical Element (SCE). Various components such as casing, gaskets and mechanical seals and dry gas seal were discussed, threats and possible damage mechanism and improvements were shared.
Basically, the mechanical seal by design is not a positivesealing like static flangetoflange connection, but rather has always had some acceptable leakage. The question of "how much leak is acceptable" was tested at site, the results analyzed and compared for safe operation. Leading damaged mechanism such as presence of liquid in the DGS in centrifugal compressor application were also discussed.
Lessons learnt related to early failures due to seal, seal cooling system, maintenance practices for correct seal installation post repair works were discussed. Besides that, damage mechanism from the contaminants such as sand in the product and damages tocasing and seals due to erosion and impingement were also discussed. Condition monitoring techniques that can be employed for reliable operation of the pump and compressor seals were also discussed. The article also describe some of the best practices that could improve the reliability of seals.
Autonomous Inflow Control Devices (AICDs) are a relatively new technology with the potential to improve the production performance of horizontal wells. The devices control the inflow of reservoir fluid to equalise influx along the length of a horizontal well, and adjust the level of constraint depending on the fluid flowing such that water production is hindered and oil production is promoted. In order to assess the effectiveness of autonomous ICDs compared to passive ICDs, which apply a constant level of restriction, numerical simulations and sensitivity studies were conducted.
A detailed model of the lower completion of a theoretical horizontal well was constructed using an Integrated Production Modelling (IPM) simulator. ICDs were represented using an Inline Programmable Element and equations to calculate the pressure drop of a range of different passive and autonomous ICDs were input. Simulations run on this model allowed the pressure drop across each ICD to be analysed, and the liquid rates at the heel and toe of the well to be compared, to assess how effective the ICDs are in promoting a balanced influx from the reservoir along the entire horizontal length of the well. Oil viscosity, heterogeneous permeability, and oil-water-contact levels were then varied to evaluate the behaviour of the ICDs in different scenarios.
Analysis of the simulation results suggests that none of the tested ICDs are the best performers in every scenario. The Rate Controlled Production (RCP) Valve AICD is the most effective device in heavy oil wells and in wells with uneven oil-water-contacts. The EquiFlow AICD is the optimum performing devicein a reservoir with heterogeneous permeability, and the nozzle ICD is the most effective device in light oil wells. Comparative study of the behaviour of passive vs autonomous ICDs indicates that there is a difference in performance between these two types of ICDs. In some cases autonomous ICDs can provide significant benefits, where as in others the passive ICDs are just as effective.
Liu, Yifei (China University of Petroleum) | Dai, Caili (China University of Petroleum) | You, Qing (China University of Geosciences) | Zou, Chenwei (China University of Petroleum) | Gao, Mingwei (China University of Petroleum) | Zhao, Mingwei (China University of Petroleum)
This article presents a novel organic-inorganic crosslinked polymer gel, which uses resin-silicate as the organic-inorganic crosslinker, to extend the temperature limitations of currently used polymer gels for water control in mature oilfields. The gelation performances, including gelation time, gel strength and thermal stability, were studied, and the optimum composition was selected by study of gelation performances. Results show that with increase of the concentrations of components, gelation time became shorter and gel strength was improved. And the gel system was stable after 90 days at 140 °C. The optimum composition of the gel system was selected as: 4~7 wt% resin and 2~5 wt% silicate with 0.1~0.3 wt% polymer. Meanwhile, differential scanning calorimetry (DSC) measurement was used to investigate the maximum tolerated temperature of the gel. The results showed that the chemical bonds of the gel began to break at 156 °C, which indicated that the gel can resist high temperature up to 156 °C. At last, environmental scanning electron microscopy (ESEM) microstructure and fourier transform infrared spectroscopy (FTIR) spectrum of the gel were studied to analyze the gelation process and investigate the mechanism for temperature resistance. The three-dimensional network microstructure of the resin-silicate crosslinked polymer gel was more compact and more uniform than the gel prepared without silicate. The formation of silicon-oxygen bonds (Si-O) increased the crosslinking density and temperature tolerance of the gel system.
The best way to maintain the base production since there is no drilling, fracturing, and limited rigless activity in mature field (Nilam field) is by reactivating cyclic wells, opening or shutting the well in for certain period of time. Hundreds of string, extensive area, and short period of cycle time make ineffective job since there are limited number of operators to handle. A design of automatic system to open or close cyclic well is created to solve the problem.
This automatic system named "autocyclic" modifies well instrument system. The method is by adding a pair of pressure switches to create pressure span between pressure setting value to open and close the SSV. When the shut-in pressure reaches the open pressure setting value, the SSV will automatically open and gas can flow, when the flowing pressure decline and reach the close pressure setting value, the SSV will automatically close. Using SSV as open and close mechanism does not eliminate its main function as safety valve.
The application of "autocyclic" is optimized based on well flowing time and pressure. The value of pressure switch setting is adjusted based on the history of the well and can be optimized to get the optimum cumulative production. Due to safety reason related with plant, the well is still choked. The result is astonishing reflected from there are 7 string installed in 2016 with total gain 1.31 MMscf compared with those wells produced in natural cycle. In the first semester 2016, those wells contribute 0.1 Bcf as cumulative production. These modifications cost around $ 608 per installation that mostly uses ex-used materials. In addition to low cost and production gain, "autocyclic" helps operators to prioritize more important tasks in the field.
Autocyclic is a simple double advantages technology. In addition to safety, well flowing cycle can be optimized and improved.
In the current low oil price context, operation of low productive asset is very challenging, particularly to maintain the integrity while production deliverable is not significant. This situation is experienced in Tunu Gathering and Testing Satellites (GTS) operation, where 4 out of 39 GTS have been confirmed low producers since the last 4 years. For optimization scheme, preservation was proposed where GTS-H was selected as pilot case. This paper will focus on detail assessments that carried out during preparation phases, including stakes review, preservation scheme definition, safety, cost benefit analysis, and overall impact to operation.
Result of GTS-H pilot project confirmed that preservation is a cost effective method to continue operation of non productive asset. Project management approach is an applicable method to execute low cost preservation, which is recommended to be applied to other low producer facility. Comprehensive review at preparation stage is outmost important, not only cost – benefit review, but also all operational aspects, most importantly safety and integrity related. Changes in operation scheme after preservation shall be assessed properly and justified with risk base analysis.
For the past several years, crude oil prices have fallen at an unprecedented level which put the oil and gas industry at the downturn state. As a result of this downturn, the industry responded by lowering down CAPEX and OPEX investment to find new reserve, sustain or increase production and arrest production decline rate. Additional production by means of drilling becomes more challenging as the investment cost especially in offshore environment is very high. One of the way that that most of the operators choose to maintain and/or arrest decline of production is by intensifying the well intervention activities. However, the legacy of high oil price has caused decades of value leakages in well intervention that need to be reduced to reflect low price environment.
Malaysia Petroleum Management (MPM), the regulatory arm of PETRONAS, spearheads a nationwide Cost Reduction Alliance (CORAL) program to reduce overall upstream industry spending in Malaysia. One of the focus of CORAL program is to challenge the value leakages in well intervention by launching Lean Well Intervention initiative. The Lean Well Intervention initiative has an objective to reduce overall well intervention spending in Malaysia by 3 % in the first year and total of 10 % within the next 4 years.
This paper outline the journey of CORAL Lean Well Intervention program in Malaysia. MPM performed detail analysis of overall well intervention spending in Malaysia and summarized three key areas that shall reduce the cost but at the same time do more well intervention activities to maintain production and/or reduce decline in production. The selection method of the three key areas with criteria to have sustainable cost reduction shall be described in detail as well the implementation phase that emphasizes on communication with all the key stake holder. Another challenge is to ensure that the reduction in cost and improvement in efficiency will be sustainable and will not be reversed if there is an increase in oil price. These three key areas are; optimizing well intervention operating model, selection of fit for purpose technology, and contract management.
As the result of these three key areas, total of more than 20 % cost reduction was achieved in the first year of implementation. This has allowed more well intervention activities to be executed and contributed higher production gain from the previous year. As a closure, the result of the program with comparison of previous year cost spending, activity level, and production generated and how it is finally embedded in the system as business-as-usual practice shall be discussed at the end of the paper.
Tiwari, Amitosh (BGEPIL, a subsidiary of Royal Dutch Shell plc group of Companies) | Fartiyal, Prashant (BGEPIL, a subsidiary of Royal Dutch Shell plc group of Companies) | Malik, Ankit (BGEPIL, a subsidiary of Royal Dutch Shell plc group of Companies) | Sharma, NeelMani (BGEPIL, a subsidiary of Royal Dutch Shell plc group of Companies) | Manickavasagam, Chandran (BGEPIL, a subsidiary of Royal Dutch Shell plc group of Companies) | Lele, Sarang (BGEPIL, a subsidiary of Royal Dutch Shell plc group of Companies) | Sharma, Aastha (BGEPIL, a subsidiary of Royal Dutch Shell plc group of Companies) | Sabhapondit, Anindya (Nalco Champion Dai-ichi India Pvt Ltd)
Calcite scaling is a major production challenge in many mature oil fields. One of the most effective manners to control calcite scaling losses is to predict the scaling behavior in the wells using thermodynamic models and then use prediction results to build an operational program to control scaling in the field using a combination of effective acid washes and scale inhibitor (SI) injection. This paper presents a case study from a mature oil field and details the operational facets of scale prediction and control program. It describes both operational challenges as well as cost optimization involved in program implementation in the field.
There are three major aspects which are discussed in this paper. First part deals with selection of right scale inhibition chemical for a field. It details laboratory experiment that was used to select the most appropriate chemical for the field. Also, this section describes the hardware infrastructure that should be in place to ensure effective implementation.
Next section deals with the trial of chemicals, selected from lab analysis, in actual field conditions. Impact of scale inhibitor in controlling scaling within the tubing and flowarm of the wells is discussed. Secondly, benchmarking of new scale inhibitor chemical performance against the existing chemical is also presented in this section. This formed the technical basis for change in existing scale inhibitor and going for full fledged implementation in the field.
Final part of the paper details field-wide implementation of scale inhibitor injection and chemical performance monitoring program. Critical parameters for chemical performance monitoring and field data on chemical dosage optimization using these critical parameters are presented. This section also presents several case studies showcasing impact of scale inhibitor injection on the well performance.
This scale management approach has not only helped in terms of reducing production losses but also assisted in improving safety performance. Field data, highlighting the impact of scale inhibitor in significantly reducing the scaling in the wells, is shared in this paper. Post implementation of this program, asset has been able to reduce its scaling related production losses significantly (~90% reduction in less than 2 years).
Once an oil field enters decline phase of its life cycle, reservoir pressure drops and water cut increases – conditions which favor high scaling behavior in the wells. Thus, scaling related losses presents a serious challenge in controlling production decline in a mature oil field. By adopting the operational practices shared in this paper, many mature oil field can benefit by reducing scaling related losses.
Reservoir Mapping While Drilling tool, consisting of a Deep Directional Electromagnetic Propagation Resistivity (DDEM) Logging While Drilling (LWD) tool and associated imaging software can detect bed boundaries and map reservoir bodies laterally beyond the wellbore being drilled. It has been successfully deployed to resolve and overcome geological and reservoir uncertainties when drilling wells offshore Malaysia. In Case Study-1, the DDEM tool was used to locate and navigate the drilling borehole assembly within a turbidite target reservoir successfully. In addition, the Reservoir Mapping While Drilling tool was able to detect and map a hydrocarbon bearing sand ten metres below the original borehole. In Case Study-2, the DDEM tool was used to identify the current Gas Water Contact (GWC) in a carbonate field which was experiencing high water cut early in the life of the field. In Case Study-3, the DDEM tool was used to determine the Top of Carbonate (TOC) in a carbonate gas field. It was critical that the top of carbonate be identified correctly, as the surface seismic data was relatively poor and was not able to pinpoint the TOC accurately. In the first case study, the hydrocarbon pay sand would have been completely missed if standard LWD tools alone were used to drill the well in a mature field. In the second case, the DDEM tool was able to locate and map the current Gas Water Contact (GWC), which was found 35 metres below the wellbore, in the carbonate gas field. It was found that the water was being produced through a karst zone, although all the previous production wells had been drilled horizontally way above the original GWC. In the third case, the DDEM tool was able to detect the Top of Carbonate, thereby allowing to set the casing shoe above the TOC. The plan was to set the intermediate casing shoe just a few metres above the TOC to avoid encountering severe mud losses when drilling through the carbonate reservoir. This paper will discuss the various steps involved in planning, designing and drilling of these wells using the DDEM tool with the associated reservoir mapping software. The methods used in imaging the reservoirs of interest and the bed boundaries and results obtained will also be discussed.