A common goal in unconventional plays is to create a sweet spot map by integrating all available data, including seismic data. This map could be utilized to optimize future drilling locations. Thus, in order to establish the workflow, we conducted a sweet spot mapping study in the Lower Triassic Montney tight gas play in the Western Canadian Sedimentary Basin, specifically focusing on prediction of lateral variations in condensate-gas ratio (CGR). A 3D geomodel was first created to obtain the 3D distribution of reservoir quality and completion quality properties which are expected to be potentially correlated with CGR. In the model, simultaneous AVO (Amplitude Variation with Offset) inversion results were fully utilized by geostatistically integrating with the well log data. Typical SRV (Stimulated Reservoir Volume) geometry in the study area was estimated from analysis using production data and microseismic data. For each producing well, average values for the reservoir quality and completion quality properties within the estimated SRV were obtained from the 3D geomodel to directly compare with the CGR value. Statistical analysis including crossplot and multiple-regression analysis was conducted to investigate the effectiveness of model properties as predictors of CGR. The analysis result implied that the reservoir depth and gas content are the most dominant properties for predicting lateral variations in CGR at seismic-scale. The reservoir depth is interpreted as a first-order control of thermal maturity and CGR. High gas content and low CGR is also observed in areas of higher porosity, which may correspond to secondary migration pathways for methane (
The protection of the critical national infrastructure involving oil, gas, water and electricity is vital for the functioning of every country's societal and economic well-being. The selection of high performance and cost effective monitoring solutions for the safety and security of both the people working on offshore platforms as well as locations of national critical importance is crucial. Marine radar surveillance systems can provide early and rapid detection and notification of marine hazards or threats. Trends in various threats to critical infrastructure, such as from terrorist and criminal activities, have created a shift towards a stronger perimeter security model with a focus on countering irregular, asymmetrical threats within a nation's coastal security zone or a localized offshore platform security zone. This has necessitated a change towards smaller, integrated surveillance platforms with associated technologies that serve multiple operational profiles. Separating cooperative targets, using technologies such as AIS, from uncooperative or unidentified targets, has become a priority for many who operate in the maritime environment.
Sensor systems that provide an enhanced 24 hour level of detection and tracking capability in littoral environments that also are cost effective and can be configured across a wide number and range of platforms and locations provide exceptional value in both performance and cost.
Rutter Technologies has developed an enhanced radar processor system, the sigma S6, which provides a superior detection and tracking capability through the implementation of scan averaging and signal processing, making it ideally suited for small patrol vessels, other enforcement platforms, commercial shipping vessels, oil & gas platform operators, and coastal/port security applications.
Data acquisition is one of the most critical parts to a sound reservoir management across the whole petroleum industry history. There are more challenges in brown fields, especially offshore fields. With the pace of moving to digital oil field (DOF), more surveillance equipment and methods are becoming available. Hence oil recovery could be improved with more accurate reservoir management. Maximizing the utilization of testing equipment and acquired data are becoming more fundamental than ever.
This paper presents two field cases from one of the biggest offshore fields. The first case is to maximize the value of available testing equipment through optimizing data acquisition plans. The second case shows a trial of maximizing utilization of the acquired data.
As one of the steps moving toward digital oil field, MultiPhase Flow Meter (MPFM) has been installed for more frequent flow tests. In addition to normal flow tests, this paper presents a new role for MPFM, which is to identify communication between strings in dual-string wells. Communication between strings is a high potential risk in this giant offshore field, because majority of the wells are dual strings. Wells with communication between strings have been identified during routine flow tests with no extra cost. In order to assure the feasibility of this approach, conventional communication test through downhole pressure measurement has been performed. Using MPFM to do communication test can save a considerable amount of expenditure comparing to the conventional method. Early actions can also be ensured to avoid reservoir cross-flow. Besides, the volume of communication can also be measured, which could help decide the optimum rate and optimize back allocation.
The flow test results are fundamental data for reservoir management and field development. The widely used results are the fluid flow rates. However, the value of temperature data was not fully revealed. The paper presents an empirical correlation derived from measurements. The empirical correlations between WHFT (Well Head Flow Temperature) and flow rate have been generated for each oil production string based on flow test data. The high quality correlations have been utilized to optimize back allocation with conditions. The value of the empirical correlation is more prominent when there are unseen obstructions in the production system. The temperature data in daily operation also indicates abnormal well performance (e.g. DHSV malfunction, scale deposition). Early actions can be planned and taken to avoid further production loss and improve operation efficiency.
The two field cases in such a brown field happened in a pre-DOF age, which also shed light on the bright future of digital oil field and better reservoir management.
Abu Dhabi fields are influenced by strike-slip and their damage zones as a main tectonic regime. A damage zone is the deformed volume of rocks around a fault surface that results from the initiation, propagation, interaction, and build-up of slip along fault segments. These damages zones impacted the distribution of the traps, migration pathways and increasing the drilling risks. Slippage and rotation along the fault segments in Abu Dhabi fields increases the damage zones widths around the fault segments. This paper presents a detailed description of the kinematics and dynamics of rotated damage zones in the strike-slip faults of Abu Dhabi fields.
The factors that are controlling the damage zones around faults are mainly the rock type, relation between bedding and fault plane and stress tensors. This paper, however, focuses on the structures within the damage zones as they are influencing the trapping mechanism, the drilling hazards and how the rotation increases these. In addition, the structures formed at the fault tips are also considered, especially for the initiation and propagation of the fractures. Field examples and outcrop analogues of damage zones around strike-slip faults are presented. This study is integration between seismic, cores, logs, and outcrops.
During the Late Cretaceous the kinematics of Abu Dhabi fault system changed to transtensional and accommodated a major component of left-lateral strike-slip motion with a SE-NW compressional component. The final phase occurred by the Miocene time, where the stress tensor is changed to NE-SW compression, which rotated the blocks. During this deformation, the blocks were dissected into a series of large-scale blocks bounded by NW-trending left-lateral strike-slip faults which merge into a NE–SW fault system that forms the main structures in Abu Dhabi. Field studies on the mountains exposures data from the fault bound subsurface blocks indicate 10°–15° of post-Early Miocene anticlockwise rotation with substantial latitudinal motion.
The decrease/increase of stresses along the fault segments in the overlapping/linkage zones and at the fault tips under differential confining pressures affecting the rocks behavior and understanding of these will greatly avoid drilling dry holes and reduce the drilling risks.
Section milling is a common method for casing removal during well abandonment applications where annular well integrity is compromised or questioned. The removal of casing by milling a window provides full access to the virgin formation, enabling placement of a rock-to-rock barrier.
Retrieving the metal cuttings (swarf) created by the milling process to surface and handling them on surface is a time-consuming and costly operation associated with health safety and environmental (HSE) risks. A joint operator/service company technology development project of a section milling without swarf to surface system now provides a novel solution.
This paper discusses the design, lab-testing and wellsite testing iterations that led to a fully functioning system for establishing a true rock-to-rock barrier without the nuisance of swarf at surface.
The new method entails milling in an upwards direction away from the swarf deposition. Currently, all section milling operations mill downwards. The system consists of the following components: taper mill, auger, section mill, emergency release disconnect, jet sub, left-hand rotating mud motor and torque isolation assembly.
The concept of milling upwards, mandated left-hand rotation to prevent casing couplings from backing off, paired with the desire to deploy on right-hand drill pipe resulted in designing and manufacturing of a custom-built left-hand mud motor. Developing a capable torque isolation assembly was not without hurdles; excessive vibration during early tests led to significant improvements to the torque isolation system, which now provides a robust solution. Creating the swarf proved to be the easy part. Downhole swarf management was more challenging, and an auger system was developed to mitigate the earlier issues encountered.
Multiple tests, evaluation and step-by step system improvements ultimately culminated in a fully functioning system, now ready for its first field deployment. A more efficient and cost-effective removal of casing by downhole deposition of the swarf created from the casing section milling operation, will reduce operational time related to plug and abandonment (P&A) operations. Multiple enabling technologies provided the stepping stones for this system and will be highlighted individually.
A giant mature light oil field under miscible WAG injection is a potential candidate for foam application to control gas mobility and reduce field gas – oil ratio (GOR). We conducted a feasibility study which comprised live oil corefloods at reservoir conditions and compositional numerical simulation coupled with a foam formulation. The objectives of this study were to identify critical variables and potential detrimental factors for the process implementation; and evaluate the GOR decrease due to foam application.
This feasibility study comprises an evaluation of the effect of foam on a field scale through numerical simulation, and the study of foam creation under reservoir conditions through coreflood experiments. We used a compositional simulator with an empirical foam implementation to predict the effect of foam in a mechanistic sector model of a high production area of the field. Simulation results show that foam is able to reduce field GOR by reducing the mobility of injected gas in high permeability layers. It became clear that the incremental oil production is strongly dependent on gas production limits; thus, foam application has to be coupled with overall field optimization.
Due to challenging field conditions for foam application, we performed an extended laboratory study. Static mixing experiments allowed surfactant compatibility limits in mixtures of formation and injection brines to be defined. In addition, a series of corefloods showed that foam can be successfully generated with a commercial alpha-olefin-sulfonate surfactant under reservoir pressure and temperature in presence of live reservoir oil, rich hydrocarbon gas and injection brine.
To our knowledge this is the first published feasibility study of foam application in a mature miscible WAG project including compositional simulation and live oil corefloods with rich hydrocarbon gas injection under reservoir conditions.
In some of the giant extra-heavy oil fields from the Orinoco Oil Belt (OOB), the challenge is to increase recovery over primary production by about 10%, to meet its ambitious development plan. To get this, it is necessary to apply EOR processes.
It is visualized the integral design of a cyclic steam stimulation (CSS) pilot test, using a high steam injection rate. It is identified and quantified the main variables and operational parameters affecting the performance of CSS, for an oil field at OOB.
The design of this pilot test covers the location of the area, visualization of thermal well, identification and quantification of the variables that potentially influence to a greater extent the performance of this technology, conceptual design of EOR surface facilities and a complete monitoring plan.
A cluster with 10 long horizontal wells of different lengths is evaluated. The variables studied are: specific steam flowrate per unit length of well, well length, and well thermal insulation. We apply design of experiments to select the combinations of the values taken for the different variables. The duration of the different stages in every cycle is given by previous results applying optimization of CSS to sector modeling.
The main constrains dictated for the thermal well are identified and taken into account to define the maximum steam injection and production rates for this test.
The pilot test is simulated for three complete cycles, with two approaches: High (2.2 – 3 bbl/day*ft) and Low (1.5 bbl/day*ft) specific steam flowrates. Important production variables as drawdown, bottom-hole pressure, field average pressure, gas oil ratio and water cut have been evaluated.
Results for the main operating parameters (High/Low approaches), and the economic evaluation, are shown. These results show once again that higher specific steam flow rates get higher recovery and are even more profitable.
The study encourages a review of the paradigm that limits steam injection rates in high-productivity projects currently underway at OOB. Additionally, it is identified that at present is the thermal well and not the surface facilities, which limit the application of CSS at higher rates, needing an urgent improvement in its concept.
The steam injection rate is conventionally expressed as daily rates (bbl/day), absolute amounts per unit thickness of formation (bbl/ft), etc. This practice creates misunderstandings, especially in the case of horizontal wells. The variable proposed in this study (specific steam flow rate per unit length of well) is valid for any type of well, and it has a physical significance related to well injectivity.
Another novelty introduced in this study is a higher specific steam flow rate (2.2-3 bbl/day*ft), between 50% and 100% higher than references found in the literature (1.5-2 bbl/day*ft).
Water Injection is a part of secondary recovery to sustain Reservoir pressure and improve sweep efficiency and consequently improve recovery factor of the field with minimum cost. Source of the water is varying between offshore and onshore fields.
Normally for all offshore fields, water injection source is sea water. However, it is vital to have proper water injection treatment system to avoid the risk of issues at surface and subsurface levels.
This case study will show how water injection treatment system is important and their impact on the decrease of water injection efficiency due to plugging and corrosion. In addition, it will show the proper mitigation plan for improvement of water quality for short/mid and long term planning of the field development.
Injected sea water should be treated mainly from the following parameters: Sand solids from the sea using the sand filters Oxygen removal from corrosion Bacteria’s Chemical inhibitors.
Sand solids from the sea using the sand filters
Oxygen removal from corrosion
Each of these parameters was checked and improved on the field and successful results were observed in terms of pipeline conditions and injection sustainability.
Due to the poor water quality, every year 15-20 water injectors were plugged or decreased dramatically due to water quality. Improving the quality of the water and setting the proper guidelines for the treatment standards showed a positive impact on injection sustainability and consequently improved production offtake from the field.
The holistic approach of the water injection treatment system and mitigation plan become possible uses the right standards of the treatment and correct surface facility. This will help to sustain water injection rate and decrease the number of acid jobs performed due to a decrease of the performance. Solving the cause of the problem is crucial instead of acting on the consequences.
Iron sulfide scale is one of the major flow assurance issues for the oil and gas fields. Mechanical descaling is currently applied, but it is time consuming and costly. Dissolvers based on concentrated hydrochloric (HCl) acid have high dissolving power, but they also have limited applicability due to overwhelming drawbacks such as corrosion and H2S generation. This paper presents the latest development of alternative iron sulfide scale dissolvers for downhole applications.
The selection criteria of alternative iron sulfide scale dissolver are high dissolution performance, low corrosion to carbon steel at elevated temperature, no H2S evolution and no formation damage. Three typical conventional iron sulfide scale dissolvers (THPS, pH neutralized chelate, and traditional chelate), along with 15wt% HCl were used as reference to compare the performance of the newly developed dissolver. Static dissolution tests and general and localized corrosion tests at elevated temperature were carried out to evaluate the dissolution and corrosion performance. Dynamic core flood tests were performed to investigate the potential formation permeability alteration when the chemical enters into the formation near wellbore, and CT scan was conducted to investigate the effect of dissolver on reservoir stimulation.
Test results indicate that the new non-acidic iron sulfide scale dissolver is an efficient and cost effective alternative for removing iron sulfide dominated scale deposited in downhole tubular and near wellbore. Results showed the new developed dissolver performed significantly better performance in term of iron sulfide dissolution capacity and much lower corrosion at high temperature. In addition, this new dissolver has no H2S generation and iron sulfide re-precipitation problems, which is significantly improve the efficient and safe operations. Moreover, it showed multifunctional characteristic of well stimulation, addressed and confirmed by dynamic coreflood evaluation and CT scan.
The new developed iron sulfide dissolver can mitigate iron sulfide deposited in tubing, near wellbore, and topside facilities with issues of iron sulfide black powder and schmoo.
Biswas, Aakash (Shell Iraq Petroleum Development) | Jumah, Ali Al (Shell Iraq Petroleum Development) | Lalji, Farhad (Shell Iraq Petroleum Development) | Doush, Mohamad (Shell Iraq Petroleum Development)
One of the principle inputs to project economics and all business decisions is a realistic production forecast. This becomes particularly challenging in supergiant oil fields with medium to low lateral connectivity. In this case, three distinct production forecasts were generated: Short Term (ST) – 3 months Medium Term (MT) – 2 years Long Term (LT) – 5+ years
Short Term (ST) – 3 months
Medium Term (MT) – 2 years
Long Term (LT) – 5+ years
The main objectives of the Medium Term Production Forecast (MTPF) are: Provide an overview of the total expected production profile, expected wells potential/ spare capacity Highlight the requirements to maintain production targets Provide an anchor point for the ST and LT production forecast generation
Provide an overview of the total expected production profile, expected wells potential/ spare capacity
Highlight the requirements to maintain production targets
Provide an anchor point for the ST and LT production forecast generation
The main tool used for MTPF was Integrated Production System model or IPSM (GAP © PETEX) since it can predict reservoir behavior, honor physical constraints and capture bottlenecks and back-pressure effects within the production system. The different components of the IPSM are the reservoir component, well component and surface network.
This paper covers the methodology for building the reservoir component of the IPSM to evaluate and accurately predict reservoir performance in the MT period. The IPSM model is not only used for the MTPF generation, but also for real time Production System Optimization (PSO), key decisions regarding well hookups, etc. by the Well, Reservoir and Facility Management (WRFM) team. There was a business need to build a pragmatic IPSM model with an optimal run time.
Thus, tank models were built to replicate the 3D reservoir models which had been built in MoRes™ (dynamic reservoir simulator developed by Shell). The MoRes™ model was divided into multiple sectors (tanks) based on pressure sinks predicted by the model and supported by geological studies.
From the MoRes™ model, a Grid cell Pressure histogram (Pressure versus frequency plot) was used to divide the reservoir into certain sectors. A close-to-normal distribution per sector was obtained to divide the reservoir into an optimal number of representative sectors. This was done because a single pressure value per sector is used by the well models connected to the sector to calculate the inflow performance in IPSM. Acquired Static Bottom Hole Pressures (SBHPs) in wells were used as anchor points for the calculated average pressure of the sectors and to test the validity of the divided sectors.
This methodology has been tested successfully in the stated super giant oil field, which has both sandstone and carbonate reservoirs. An example this is covered in the paper. It was concluded that utilizing multiple sectors (tanks) results in reservoir pressure decline predicted being closer to what is actually seen by the wells. The IPSM model built represents reality sufficiently well in the MT period, thus increasing confidence in the generated production forecast. Another technical advantage of the described method is the higher sustainability of the model.
The suggested histogram method, in combination with geological information available, can be applied to majority of the reservoirs. This combination is paramount to ensure the divided sectors concur with reality.