High pressure pumps used in oil well stimulation are usually powered by diesel engines using multispeed transmissions. Many high pressure well service pumps are reciprocating single-acting positive displacement pumps, mounted on a specially designed trailer chassis frame at a certain height to perform well servicing operations. These pumps require frequent maintenance at fluid ends (discharge area).
These maintenance operations require the technician to place his or her hands inside the fluid end to replace valves and related components. This is potentially problematic when the pumping equipment is remotely controlled and the person starting the engine might not have a clear view of the pump. During maintenance of the fluid end, it is necessary to rotate the input shaft of the pump to retract the plungers out of the way to access the valves. The equipment technician often must stand at an elevated height to perform these maintenance tasks, and must manage and hold various tools and equipment to perform this job. This can involve significant risk in terms of human factors, operational safety, and control of falling objects.
This paper addresses how a retrofitted safety work platform was incorporated into fracturing pump trailers to more safely perform effective maintenance. The real field operation conditions, field engineer’s input, and district requirements, such as railings, ladder position, and gratings are considered. In addition, different variables, such as road travel positioning, duration of work, frequency, task difficulty, work envelope, and ground level access requirements were evaluated during design and installation of the work platform on the unit at the field operation.
An ergonomically designed work platform adds benefit by providing worker stability, minimizing postural fatigue, and anthropometry, thereby reducing risk of personal injury incidents while performing maintenance of equipment at an elevated height. This outlined approach to increased safety will be useful to engineers, operators, and safety professionals to help reduce risk and improve worker performance.
Hydraulic fracturing is a well stimulation technique that was first tested in the oil and gas industry in 1947, and the process was accepted commercially by 1950 (King 2012). To perform hydraulic fracturing operations, a fluid must be pumped into the well’s production casing (or a treating string) at a high pressure. It is necessary that production casing has been installed and cemented, and that it is capable of withstanding the pressure for which it will be subjected during hydraulic fracturing operations. The hydraulic fracturing process requires an array of specialized equipment and materials. These materials and equipment are necessary to perform typical hydraulic fracturing operations in vertical and horizontal wells. The equipment required to perform a hydraulic fracturing treatment includes fluid storage tanks, proppant transport equipment, blending equipment, pumping equipment, and all ancillary equipment, such as hoses, piping, valves, and manifolds. Before beginning the hydraulic fracture treatment, all equipment should be tested to help ensure it is in good operating condition. All high-pressure lines leading from the pump trucks to the wellhead should be pressure tested to the maximum treating pressure. Any leaks must be eliminated before initiation of the hydraulic fracture treatment (American Petroleum Institute 2009).
Hydraulic pumping trailers located or installed at rig sites are primarily diesel powered high pressure pumping units designed for oil well stimulation. Typically, a pumping trailer unit consists of diesel engines, transmissions, and triplex or quintuplex pumps equipped with advanced digital controls for transmissions and engines. The fracturing trailer unit needs frequent maintenance of various systems such as fluid end lubrications, recirculating air/oil systems and grease systems. Fig. 1 shows a typical example of a modern diesel powered fracturing pump trailer.
The propagation of seismic waves through visco-acoustic media is affected by frequency dependent absorption which is often described by the quality factor Q where a low Q means more loss of signal strength and bandwidth. Complex variations in attenuation, if not accounted for, can severely compromise both the amplitude and phase of the migrated data. This in turn affects the ability to accurately predict reservoir properties. In this paper we propose a new tomographic approach using adaptive centroid frequency shift (CFS) information from surface seismic data to estimate Q.
By picking the events in the migrated section and ray-tracing back to the unmigrated data domain, the centroid frequency of the unmigrated data can be measured for the picked events in the depth migrated CIG gathers. After applying the correction generated on the fly for the given source wavelet, these adaptively corrected CFS will then be back-projected along ray path to reconstruct the attenuation distribution through our tomographic inversion.
A synthetic test and a real data example will be presented to demonstrate how our approach can accurately estimate a Q model and can be included in the Q compensation process to fully account for the frequency dependent attenuation effects observed on seismic data.
A key element of the CFS method is deciding what analytical function should be used to fit the amplitude spectrum of wavelets before and after passing through visco-acoustic media. However, we found the accuracy of Q tomographic inversion to be sensitive to the accuracy of the fitting and that the fixed wavelet fitting function cannot describe the real source wavelet accurately. An adaptive correction is applied to the observed centroid frequency to account for any deviation from the explicit relationship through tabulating the absorption effect for different accumulated dissipation time. These adaptively corrected centroid frequency shifts improve the stability and the accuracy of the inversion.
The propagation of seismic waves through viscoacoustic media is affected by frequency dependent absorption which results in loss of signal strength and bandwidth. Complex variations in attenuation, if not accounted for, can severely compromise both the amplitude and phase of the migrated data. This in turn affects the ability to accurately predict reservoir properties (Best et al., 1994). Thus, there is a need to compensate for the frequency dependent absorption during the processing of the data.
An approach is explored for estimating critical and maximum gas saturation using 4D seismic data from multiple surveys shot during gas exsolution and dissolution in a producing hydrocarbon reservoir. To guide this process, hydrocarbon gas properties and behaviour are studied, and their relation to the fluid-flow physics is understood using numerical simulation and seismic modelling. This understanding is then used to interpret observed seismic data, which has surveys repeated every 12 to 24 months, from a turbidite field in the United Kingdom Continental Shelf (UKCS). Furthermore, the field reservoir simulation model is then history matched to the production data and the gas saturation effects observed on the 4D seismic data. The 4D seismic response is a function of pressure changes, fluid (oil/water/gas) changes and noise. The effects of the gas mechanism are extracted from the seismic data based on its unique relationship to the seismic amplitudes. It is found that these changes can be represented by a binary model (presence or absence of gas) which enables the use of a logical objective function to compute the misfit between the observed data and simulated data, and thus guide the parameterisation process of the history matching exercise. This approach circumvents full physics modelling in a joint history matching workflow that includes conditioning to both production data and multiple time lapse seismic data. It is concluded that for seismic surveys repeated at intervals of six months or more, the gas saturation distribution during either liberation or dissolution exists at two fixed saturations defined by the critical and the maximum gas saturation. From analysing only the 4D seismic data, we find a low critical gas saturation and a maximum gas saturation that is relatively unconstrained. The history matching exercise also gives us similar low values for the critical gas saturation, and highlights the importance of the vertical permeability in getting an extensively corroborated model. This paper explores a direct link between 4D seismic and the fluid flow parameters, a link between the gas saturation distribution and seismic response, as well as a quantitative analysis using multiple 4D seismic surveys for history matching.
Huang, Jixin (Research Inst. of Petroleum Exploration and Development, PetroChina) | Fan, Zheng (Telon Hi-Tech Co. Ltd.) | Xiao, Kun (CNOOC Ltd.) | Guo, Songwei (Research Inst. of Petroleum Exploration and Development, PetroChina)
A new internal architecture modeling method was proposed for lateral accretion(LA) shale beddings of point bar sand body in meandering channelized reservoir. Based on the point bar 3D grid model and the internal architecture analysis results,three orderly modeling technology links were applied to form a full set of embedding modeling technology process and the algorithm implementation, including 3D vector field LA pattern fitting modeling, the LA thickness distribution interpolation under LA surface trend control and partial grid subdividing model embedding process. And then, the modeling method has been validated through a typical internal architecture model of point bar at a study block of China East oilfield. The results show that firstly the internal architecture modeling method can be used to establish fine 3D model of LA shale beddings which condition to wells. Secondly, using LA pattern fitting modeling technology, the method can be effectively encountering inadequate well point information, and can predict the distribution of LA between two wells. Finally, an optimized grid description of different levels and scale architecture was provided by partial grid subdividing model embedding technology. Introduction
Point bar is the most important types of sand bodies of meandering channelized reservoir. Within the point bar sand, development of LA, LA shale beddings and LA surface. Wherein, LA shale beddings are one kind of very important barrier, largely control waterflooding development, and then influence the distribution of remaining oil. Therefore, the establishment of three-dimensional quantitative internal architecture of point bar sand body model has the practical value.
It can be seen from the internal architecture model of point bar, LA, LA shale beddings and LA surfaces of the three elements. Among them, LA surface as the LA of a flushing body exists between the erosion surface; the LA shale bedding refers to the LA shale layer deposited on the surface, a more oblique insertion mud wedge in the section, the plane is arc, thickness of between 0.2m~2m. Point bar LA models generally can be summarized into three kinds, respectively is the horizontal echelon (see Fig.1A), ladder echelon (see Fig.1B), wave (see Fig.1C). This thesis research algorithm will focus on horizontal echelon and step diagonal LA pattern lateral layers as modeling objects.
The goal of modeling for internal architecture of point bar, is the LA shale beddings model embedded grid on every single point bar model(see Fig.2). To this end, first modeling method of embedded architecture surface model by an automatic model fitting surface modeling techniques used to characterize the spatial distribution of the LA; secondly, according to the LA laminate thickness data extraction for each well point, and in the LA surfaces within the scope of interpolation, to establish a model of LA laminate thickness; finally, on the basis of LA model surface and LA laminate thickness, and to the local grid refinement approach will be embedded into the point bar LA shale beddings solid model established in the previously step.
Gas hydrate formation and control is a critical flow challenge that many offshore oil and gas production operations encounter. Formation of hydrates can cause blockage of production flowlines, chokes and valves, which can result in catastrophic failures. Compared to other production problems, hydrate formation is a relatively new phenomenon that is becoming more and more significant with increasing subsea and deepwater developments as well as huge gas projects in the Middle East. The use of low dosage hydrate inhibitors (LDHIs), such as kinetic hydrate inhibitors (KHIs), offer an alternate technical solution to thermodynamic hydrate inhibitors by offering better economics, improved Health, Safety and Environmental (HS&E) performance and less demand on product transportation and storage.
This paper summarizes the history, evolution and current state of KHI laboratory testing requirements. Improvements in laboratory techniques to evaluate the performance of KHI in sweet and sour environments will be discussed. The results of the evaluation are based on laboratory conditions and the ability of a KHI to successfully inhibit hydrate formation in sweet and sour rocking cells. Recent testing has shown significant differences between sweet and sour environments and the ability of the KHI to successfully inhibit hydrate formation under laboratory conditions.
The secondary properties of a selected KHI are becoming more important so are advances in evaluating these properties, in particular the stability and applicability of a KHI under proposed system conditions. Hydrates may form different structures depending on the gas composition of the produced fluids. The nature of the KHI used needs to take into consideration. Recent product developments in this area show that these challenges can be met with appropriate lab testing.
Flow assurance is critical during the efficient production of hydrocarbons from offshore and subsea assets. Gas hydrate formation and control is a critical flow assurance challenge that many offshore oil and gas production operations encounter. The interaction of low-molecular weight gases such as small chain hydrocarbon, and acidic gases like carbon dioxide and hydrogen sulfide, with water under "high" pressure and "low" temperature within a pipeline can form gas hydrates. Gas hydrates are essentially a gas molecule encapsulated by water molecules which have an ice like appearance. Two types of hydrate structure form in gas pipelines, type II being the most common and associated with larger gas molecules such as ethane and propane and type I mainly associated with lean gas and/or carbon dioxide or hydrogen sulfide production. Gas hydrate crystals may agglomerate and/or anneal to form plugs that results in lost production and may incrase (HS&E) risks. Formation of hydrates can cause blockage of production flowlines, chokes and valves, which can result in potentially catastrophic failures.
Fractured basements are one of the more complex types of reservoirs for drilling, assessment, development, and production enhancement. While they represent some of the largest and most productive reservoirs, they decline rapidly and are prone to undesirable fluids breakthrough. When characterizing fractured basements to better estimate reservoir capacity and deliverability, it is important to understand the role that matrix porosity and fracture network play in reservoir performance. This is especially true when the reservoir has been subjected to a variable metamorphic grade during different tectonic episodes, in addition to localized contact metamorphism by intrusions.
Matrix porosity can be estimated from electric wireline and logging/measuring while drilling tools. However, for better estimation and to help minimize uncertainty, identifying the rock-forming minerals using elemental analysis on core or ditch cuttings is essential. The composition of the metasediment can be used to identify the original sedimentary rock, even where it has been subject to high-grade metamorphism and intense deformation. Fracture characterization and porosity and permeability can be estimated using resistivity or acoustic borehole imaging tools. Also, borehole seismic data can help with fracture characterization.
Fractured basement reservoir connectivity can be confirmed using wireline formation testing and sampling (WFT) or drill stem tests (DSTs). In addition, because not all open fractures produce, it is important to identify the critically stressed fractures that will contribute to production using geomechanical analysis. Comparing results from the study area with other fractured basement matrices and fracture porosity and permeability ranges was helpful in validating the analysis and predicting reservoir performance.
This paper presents a proposed workflow for a set of data acquisition and characterization technologies and methods using a local example from an offshore Malay basin. The pros and cons of each technology and methodology proposed are discussed in detail.
There are many definitions for basement reservoirs. Landes et al. (1960) state “basement rocks are considered as any metamorphic or igneous rocks (regardless of age) which are un-conformably overlain by a sedimentary sequence.”
Basement reservoir-forming rock types vary according to 1) mineralogical composition and texture for igneous rocks or 2) original rock and texture for metamorphic rocks (Fig. 1). Understanding the mineralogical composition is essential for calculating matrix porosity and can provide a better estimation of the expected range. It also indicates the probability of having fractures and what type of filling material is present in the fractures.
In principle, there are many possible sources for hydrocarbon accumulation in basement reservoirs. However, three sources are referenced most commonly (Sircar 2004):
Discrete technology solutions, such as real time data acquisition, distributed temperature sensing, etc. applied on selected-well basis seem to serve field development engineers well sometimes. Nevertheless, for engineers continually to improve field-wide operations and attain the cost and production advantages necessary to stay competitive in an industry shifting to cost-effective applications, integrating workflows is a strategic imperative. Engineers will need to concentrate and excel not just on specific technologies but on holistic rigless operations success driven by more attention to integration than individual technology solutions. The challenge facing asset teams remains how to execute comprehensive plans to make significantly higher returns from capital technology spending in the field.
The scope of this paper is to present how engineers have adopted technology integration and alignment of numerous technology solutions for the specific situation of successfully developing and managing a giant oil carbonate field in readiness for a major production milestone. The approach presented entails an all-inclusive project-based method that involves performance reviews, elimination or reduction of idle times through close monitoring of incremental project stages, optimizing operational efficiency through increasing the speed of material delivery to the well sites, and improvement of logistics of people and equipment. The approach involves unifying role-based, process-based, and production workflows throughout the operation and building on a learning curve with each successive rigless operation. From the safe job execution of over 100 rigless activities, a model or scorecard is available to control important variables, assess the effectiveness of specific technologies, and provide support for leading or lagging indicators. As a result of seamless and routine inclusion of technology-based exercises at a project level, rigless activities have been completed over 60% faster than when the campaigns started nearly five years ago. Monetizing this value of technology integration in auditable and quantifiable terms translate to significant gains over the course of the rigless campaign. Through integration, engineers can implement effective programs for improvement in service levels and improve operations. Eventually these gains translate to fewer obstacles to project delivery.
Technology is core and central to Manifa field development. Achievements in the Manifa field are testament that the field development team is savvy about applying fit for purpose technological solutions for lasting/sustainable gains. As a result of measurable improvements and integration of workflows between core technology applications, several world firsts have been credited to the Manifa team (Arukhe et al., 2014). Some of these records include the world’s largest extended reach project (more than 75% if the field’s wells are ERWs) and the use of the world’s first tandem 2.125” CT tractor for ESP open hole completions (Arukhe, Duthie, Al-Ghamdi, Hanbzazah, Almarri, Sidle & Al-Khamees (2014). The first oil industry use of a specialized reusable filtration unit system in a long-term injection test, utilizing primary seawater filtration and chemical treatment was conducted in the field. A reflection of the project, upon successful commissioning of the first phase, reveals that the most critical success factor includes the degree of technology integration into the team’s basic strategic approach to field development. The amount of solutions for rigless well interventions and well testing have multiplied considerably lately – from optimizing CT reach, well stimulation, multilateral access, and profiling to well testing. At present, these solutions deliver gains with possibility of influencing more efficient field development. As shown in this paper, technology adoption in CT reach and stimulation treatments results in gains from accelerated job execution and client satisfaction becomes evident. Consequently many wells have been successfully stimulated onshore and offshore.
Ong, Alastair (LEAP Energy) | Alessio, Laurent (LEAP Energy) | Ben Salah, Yassine (LEAP Energy) | Connell, Christopher (LEAP Energy) | Majidaie, Saeed (LEAP Energy) | Sugiarto, Isan (Arrow Energy Pty. Ltd) | Sharma, Vikram (Arrow Energy Pty. Ltd) | Mazumder, Saikat (Arrow Energy Pty. Ltd)
This paper presents a case study in the application of an advanced production data analysis (PDA) technique for coalbed methane (CBM) through the use of stochastic single-well history matching (SWHM) as a method that enables the exhaustive identification of the range of reservoir parameters underpinning the historical production, with flexibility to handle multilayered completions, and handle the transient effects present in CBM production responses. Through the application of this method, we present how to perform the quantification of uncertainties in an efficient and timely manner. It is envisioned that this technique be used as part of a wide range of methods in an effort to effectively understand complex and variable well performance seen in CBM wells. SWHM provides many advantages to traditional PDA (straight line methods) by the introduction of simplified physics coupled with material balance or radial numerical modelling, whilst retaining a significant speed advantage over traditional 3D fullfield numerical simulation. The PDA SWHM technique is applied to strengthen existing reservoir characterisation workflows, guide appraisal and data acquisition planning, and accelerate traditional static and dynamic modelling workflows. This paper presents a case study based on the single-well history matching of over 20 CBM pilot wells located in the Surat Basin. The findings presented within this paper include: connected areas and volumes drained by the wells, reservoir quality variability from well to well, and layer-wise, uncertainty ranges over forecasted outcomes (ultimate recovery, recovery factor) as a function of the available history. The effect of uncertainties in bottom-hole pressure and relative permeability on reservoir property solutions and forecasts are also presented.
Introduction: Stochastic single-well history matching workflow (SWHM) as a PDA tool
The development of coalbed methane (CBM) plays highlights many challenges that necessitate the use of new tools and workflows to facilitate appraisal and development decisions. CBM reservoirs present the following challenges:
Benlacheheb, Mohamed (Qatargas Operating Co. Ltd.) | Al Meer, Haytham Abdulaziz (Qatargas Operating Co. Ltd.) | Kandil, Ahmed (Qatargas Operating Co. Ltd.) | Ross, Fraser (Qatargas Operating Co. Ltd.) | Rimach, Millagritos (Qatargas Operating Co. Ltd.)
Permeability prediction always constitutes a challenging step in the modeling process. Reservoir heterogeneity such as diagenesis, fracturing and effective connected geobodies are the main factors complicating the prediction. Hence, limiting permeability model to core data only could lead to unsatisfactory results while history matching. As consequence, poor reservoir performance prediction will be obtained. In such circumstance, further permeability enhancement using PBU and PLT data are usually needed.
The Core or log derived Permeability captures the heterogeneity around the wellbore whereas well test data describes the reservoir in accordance with the radius of investigation. In addition to that, the measured core permeability is absolute while the fluid flow in the reservoir is governed by the effective permeability which is captured by well test data.
Having the advantage of continuous monitoring program including PLT and PBU constitute a precious and considerable piece of data. These amounts of PLTs allow capturing the vertical heterogeneity in the reservoir while the PBU tests give better areal distribution of the KH test.
A ratio of KH test over KH core can be calculated and usually assumed as a good indicator of presence of fractures. In this case, an appropriate Discrete Fracture Network (DFN) model is required to build the permeability model. However, if the ratio is indicating matrix contribution a more simplistic approach can be applied and gives reasonable results.
By identifying the contributing intervals from PLT results coupled with the KH test over KH core ratio, the core permeability is then elevated to the test permeability.
The objective of this work is to present the application of this approach in different blocks in one giant gas field which shows improvement in the permeability prediction; results are supported by dynamic analytical model performance.
Estimating effective permeability at reservoir scale is a challenging task especialy in carbonates due to the fact that their depositional process and the diagenetic history can be very complex, resulting in heterogeneity of the pore system. In addition to that, fractutres can occure in the reservoir leading to additional difficulties to characterize the permeability. As consequence of that, high permeability intervals can be developed at different scale, those streaks might not be captured by core and log data.
This paper presents an innovative approach for the design and development of Pipeline Inspection Gauge (PIG) which can inspect pipes from 15” up to 30” with a simple change of shirts using the latest technologies such as Electromagnetic Acoustic Transducer (EMAT) sensors as well as Remote Field Eddy Current (RFEC) sensors for oil pipes inspection, through the creation of a simulation tool capable of generating simulated images from pipeline using Inertial Navigation System (INS) for highest accuracy and precision inspection to protect the environment and equipment from any unexpected accident. There are several dynamo motors utilized to regenerate green efficient power from the flow of the medium inside the pipeline to elongate the distance of investigation by the mean of reduction of the number of individual pigging processes to save time and cost for companies. The INS uses accelerometers and gyroscopes of the type “Integrated Micro Electro-Mechanical Systems” (iMEMS), to carry out the mapping corresponding to the inspected pipes. Fluid hammer effect is another factor which has been considered during designing this pig. To avoid such case to occur the design has been revised and several arms have been devised around the robot to maintain the speed and position of pig all the way through the pipeline.
Pipelines are considered to be the safest way for transportation of large amounts of liquid and gas over large distances. Pipelines are one of the cornerstones of modern civilization constituting an essential part of the infrastructure. More than 3 million kilometers of pipelines connect the reservoirs of oil and gas, the ports of shipment, the refineries and the storage facilities today. Non-destructive testing of the pipeline system by means of in-line inspection using intelligent pigs has become an important part of this system in ensuring its safe and economic operation. In order to prevent pipeline failure, any defect that may become critical has to be detected early enough. As most of the pipelines are buried and also covered by a protective coating, a complete inspection can only be done from the inside. This is achieved with in-line inspection using automated inspection systems called intelligent pigs (or smart pigs). The ultimate goal of this type of inspection is to detect a certain type of defect with a high Probability of Detection (POD) and to provide high resolution data that allow precise sizing of the detected defects. (WILLEMS, 2008)
Intelligent pigs are automated inspection systems which are usually designed such that one inspection tool is looking for a specific type of defect utilizing one technology. Table 1 shows an overview. The main inspection methods that are used are Magnetic Flux Leakage (MFL) and Ultrasonics (UT).