Rumaila, Iraq, is one of the biggest oil fields in the world, producing through multiple stacked clastic and carbonate reservoirs and relying on several recovery mechanisms such as natural aquifer drive and water flooding which have changed the initial fluid distribution. To evaluate the change of fluids distribution, multi-detector pulsed neutron (MDPN) instruments are run within the field. MDPN measurements require careful interpretation accounting for logging conditions and formation environments to provide an accurate result of multicomponent fluid saturations so well work activity can be optimised, and production and recovery can be maximized. Compatibility with legacy data is also critical for use in time lapse evaluations.
Recently, the MDPN technology diversified with more instruments being developed. Field trials are required to understand backwards compatibility for some of the common nuclear attributes as well as benchmarking and calibrating the nuclear models with the in-situ measurements. While all share the same physics principle, the responses can vary owing to instrumentation design, characterization and nuclear attributes extraction in the field. We will present the data integration approach taken by the production team using historical and latest generation MDPN data, some acquired for the first time in the clastic and carbonate formations of Rumaila field.
The paper will describe BP’s in-house workflow customised for MDPN derived saturation in Rumaila. This will address the nuclear attribute screening and selection process for the two types of reservoirs (clastic and carbonate) and the associated displacement mechanisms. Data from multiple MDPN instruments are used to illustrate the robustness of our workflow that accounts for borehole configuration, formation properties, reservoir fluids properties and detailed nuclear models for each tool.
The nuclear model driven interpretation showed that logging conditions and reservoir properties can significantly impact the accuracy of fluid saturation. The uncertainty in MDPN derived saturation can be reduced if the deviations from notional values are known. Because of similar sand-clay properties, the carbon oxygen response in the clastic reservoir showed a unique pattern challenging the conventional understanding of such data. Additional to reservoir complexity, new challenges will be faced in relation to wellbore access because more wells are completed with electric submersible pumps (ESP). In ESP completed wells, the access to reservoir section will be thru Y-tools using slim MDPN instrumentation. Our study identified the optimal procedures and best nuclear attributes that can be logged in these conditions without increasing the saturation uncertainty.
We present a case-study that compares seismic inversion methods for reservoir characterisation on the Mishrif carbonates in the Rumaila field, Iraq. The two methods interrogated - Deterministic Absolute Acoustic Impedance Inversion (DAAII) and BP's One-Dimensional Stochastic Inversion (ODiSI) - were used to predict porosity. This case-study highlights benefits, limitations and uncertainties associated with these methods.
Seismic inversions produce non-unique solutions mainly due to the bandlimited input seismic, as several reservoir property profiles can result in the same seismic trace. DAAII is a widely applied Model- Based Inversion technique, which uses a Low Frequency Model (LFM, derived from well-log impedance) as input to the inversion algorithm. The algorithm uses the LFM as a starting point to seek an impedance profile that best minimises residual error between the resulting modelled synthetic, after convolution with an average of the extracted wavelets, and the input seismic trace. It accepts the inverted impedance profile when the error is minimised. DAAII typically results in a relatively smooth deterministic estimate of absolute Acoustic Impedance (AI), and the output is heavily dependent on robustness of the input LFM. This can be a severe shortcoming in reservoirs with poor well control - simply put, if the input LFM is of questionable quality (e.g. poor well-log data, sampling bias, suboptimal interpolation between wells) then the output impedance is most likely going to be inadequate at accurately predicting reservoir properties. In this case-study, seven wells within the 250km2 test area that had been tied to the seismic were used for the LFM along with three framework surfaces, and of these seven wells, four extracted wavelets were averaged and used for the inversion. Finally, the inverted Acoustic Impedance (AI) volume was used to estimate porosity using a simple linear regression.
BPs ODiSI (
DAAII and ODiSI have been successfully applied to the Mishrif carbonate reservoir in the Rumaila field. This case-study shows how ODiSI results compare against a more established inversion method (i.e. DAAII) in a heterogeneous carbonate reservoir of an onshore field. Since a primary objective of any property estimation procedure like a seismic inversion is to predict the value of a property or attribute at an unmeasured location, several wells were used as blind-tests. More blind-test wells were interrogated with ODiSI compared to DAAII, due to its minimal well input. These tests showed that despite the fewer number of wells required to run ODiSI, the results are generally better than those from the DAAII.
BP is a joint venture partner in GUPCO, which operates in the Gulf of Suez, Egypt. The asset is over 50 years old and has a large operational foot print. This includes 3 onshore process facilities handling over 450,000 barrels of fluid per day from over 100 offshore structures and 200 pipelines. The field is supported by gas lift and water injection from two onshore facilities. The asset presents a challenge from an integrity perspective, namely corrosion and production chemistry threats. These are managed through an inspection program and anomaly management process. This case study presents how our asset integrity is managed and forward plan for improvement. The important relationship with the risk management process is highlighted.
We present a case study that demonstrates the use of our robust Seismic-Well Tie (SWT) process and seismic attributes to validate the added resolution from Seismic Spectral Blueing (SSB) on the carbonate Mishrif reservoir in the Rumaila oil field. Our SWT process included Vertical Seismic Profile (VSP) corridor stack traces and Reflection Coefficient Modelling (RCM). Seismic attributes generated following the interpretation of the SSB data, revealed geological features that weren’t previously visible on the full- stack seismic. All of these provide validation that the extra wiggle from the SSB is real in this case study.
SSB outputs bandlimited reflectivity traces derived from shaping the amplitude spectra of the input seismic to that of the well log-based reflectivity series. SSB adds seismic bandwidth to the full-stack data that is expressed as an extra trough within the Mishrif reservoir in certain parts of the field. Three-way SWTs, achieved by including a VSP corridor stack trace to a more conventional tie between well log synthetic and seismic trace, is typically seen as a thorough approach. It can help to reinforce confidence in seismic events observed in all three data types and to highlight events or intervals where well logs or seismic may contain significant anomalous data. Three-way SWTs tying full-stack synthetic, full-stack seismic and 8-12-30-45 Hz VSP corridor stack traces, as well as SSB synthetic, SSB and 8-12-50-75 Hz VSP corridor stack traces are of good-quality, with a comparable extra trough also identified on the broader bandwidth VSP corridor stack trace.
Reflection Coefficient Modelling (RCM), a part of the SWT process, is a way of deconstructing a synthetic seismic trace by looking at the intermediate step in wavelet convolution to isolate the contributions of individual Reflectivity Coefficient (RC) contrasts to the resulting seismic event, often referred to as a ‘wiggle’. RCM suggests that the extra trough observed on the SSB data is associated with the development of a rudist-dominated grainstone shoal body. VSP data was used to generate both conventional primary reflectivity response, as well as multiple corridor stacks based on key interbed multiples to understand their generation and kinematics. Different wavefields were generated to allow the discrimination between surface and interbed multiples. This provides support for amplitude fidelity for multiple events and helped identify the adverse effect of multiples on a different reservoir interval trough.
Due to the large well stock, with over 700 wells with porosity logs penetrating the Mishrif reservoir, this case study is peculiar in the sense that the previous Geomodel had no direct seismic attributes used in property distribution. Therefore, seismic attributes generated were compared to the Geomodel properties, such as porosity to see if geological features were identifiable on seismic. A grainstone shoal body on a Geomodel average porosity map, also clearly delineated on the SSB sections and attributes, was only subtlely expressed and not properly identifiable on the full-stack data. One of several sinuous features, interpreted as grainstone-dominated tidal channels, targeted using seismic attributes was recently drilled and encountered good reservoir quality channel facies.
This case study shows how a SWT process (three-way tie, RCM), seismic attributes and results from a recently drilled well provide validation of the authenticity of the added SSB resolution.
The Rumaila Operating Organisation (ROO) is a consortium made up of BP, China National Petroleum Corporation (CNPC) and the Basra Oil Company (BOC) formed to manage the rehabilitation and expansion of the Rumaila super giant oil field, considered the third largest in the world. The Digital Oilfield (DOF) plays an important role in the rehabilitation process. This paper describes the major challenges, solutions and benefits over 5 years of implementation.
The development of the DOF solution involved several components: the installation and connection of sensors; a data management platform for both real-time and non-real time data; the development of engineering models and workflows; an Exception-Based Surveillance engine (EBS) and a user interface integrating all this data.
This paper details how an EBS process is handled for a field of this magnitude, the use of state-of-the-art algorithms for identification of well flow conditions, deployment of advanced analytics for surveillance and optimization of natural flow and ESP wells.
This paper also details how usability testing and advanced graphic design practices were used to guarantee maximum adoption of the new toolkit.
The Rumaila case is ideal for evaluating the added value of digitalization of oilfields since the project developed from a zero base to a fully digital system in a matter of a few years. The main success stories include: the extension of the lifetime of the ESPs; reduction in well downtime; significant time savings for repetitive tasks; improved reservoir management accuracy; the ability to more readily meet production targets; facility management and optimization; and improvement in oil quality.
The data and visualization usage figures which are continuously monitored show a year-on-year growing user base. This demonstrated that maintaining focus on continuous development and evolution, and providing top class support locally and from specialist vendors, increases user adoption.
As a result, the program has gained support at all levels in the organization, making DOF an integral part of the field operation providing high efficiency and standards of excellence.
Due to the initial lack of any digitalization in the field, this project can be considered a blueprint for modernization of fields in challenging environments, where very little digital infrastructure is initially available. This project has proven that DOF implementation can be very successful despite many localized challenges, and that a continuous focus on system evolution guarantees a growing user base year after year.
This paper presents a case history of drilling automation system pilot deployment, inclusive of wired drill pipe on an Arctic drilling operation. This builds on the body of work that BP (the operator) previously presented in 2017 related to the deployment of an alternate drilling automation system. The focus will be on the challenges and lessons learned during this deployment over a series of development wells.
Two major aspects of technology were introduced during this pilot, the first being a drilling automation software platform that allowed secure access to the rig's drilling control system. This platform hosts applications that interpret the activity on the rig and issue control setpoints to drive the operation of the rig's top drive, mud pumps, auto driller, drawworks, and slips. The second component introduced was a wired drill string, which provides access to high speed delivery of downhole data from a series of distributed downhole sensors, providing an opportunity to improve both automated control and real-time interpretation of downhole phenomena.
The project team identified several key performance indicators both at the project level and for each well. The project level key performance indicators (KPIs) were designed to give the operator an understanding of the reliability and robustness of the hardware and software components of the automation system. The KPIs for the well were designed to assess the impact of the technology on drilling efficiency through aspects of invisible lost time reduction (connection and survey times). The well level KPIs also fed into the project KPIs by capturing uptime, reliability, and repeatability of the hardware and software components of the system.
The paper describes several specific examples of where the benefits of the technology were realized as related to the KPIs above and describes some of the technical challenges encountered and fixes employed during the pilot campaign.
The paper also gives an insight into some of the non-technical challenges related to deployment of this system, around human behavioral characteristics. It discusses how focused collaboration and communication from all the stakeholders was managed and directed towards a successful deployment.
The work delivered on this project incorporates several technological innovations that were deployed for the first time on an active drilling operation. Delivery of these were important milestones for both the operator and the automation technology provider as part of their collaboration to increase the capability and reliability of these systems. The operator believes that this effort is key to allowing its drilling operations to realize longer term and sustainable benefits from automation.
Carragher, Paul (BiSN) | Bedouet, Sylvain (BiSN) | Talapatra, Didhiti (BiSN) | Hughes, Andrea (BP) | Curran, John (BP) | Hou, Wei (BP) | Kosi, Orlando (BP) | Ralph, Stan (BP) | Gao, Qiang (BP) | Gracia, Jesse (BP) | Galvan, Jeanine (BP) | Calvert, Patrick (BP) | Alcoser, Luis (BP) | Dean, Doyle (BP) | Mason, David (BP)
Achieving water shut-off in gravel packed wells is challenging, particularly being able to place a mechanical barrier to flow into a gravel packed annulus. Gravel packed wells, often in deepwater environments, are often high rate wells and interventions can be costly, therefore only techniques with a high probability of success are typically sanctioned.
Many gravel pack wells are completed in multiple sands. If there are barriers between the sands that are believed to be laterally extensive, and if water is entering the lower sand, then isolating the lower sand can be a cost-effective intervention. Deepwater wells in Angola were reviewed as to whether a chemical solution or a mechanical solution would be preferred.
Providing a suitable mechanical methodology could be developed, it was felt this would provide a preferred solution. Further criteria for applying a mechanical solution were developed, to increase the chances of success. Extensive well modelling was also conducted to identify an optimum set of plugs to be placed in the well.
The operator identified a company that had an emerging technology that could offer such a solution. They then worked together to mature the technology through a series of proof-of-concept tests, through trials in Alaska, an early application in a deepwater well in the Gulf of Mexico, followed by a series of qualification tests to be ready for application in Angola. The qualification tests considered not only the mechanical configuration of the wells, but temperature, pressure and wellbore deviation. The application would require placement using a tractor, therefore testing with connecting to the relevant equipment was also incorporated in the plans for the wells.
Using a deepwater rig, several plugs were run in each well, including a meltable alloy plug. The latter plug provided a barrier to flow in both the annulus and inside the sand screens. Although not providing a barrier to shunt tubes, extensive modelling work at Cambridge university showed that it was possible to influence gravel movement in the annulus and shunt tubes, so as to maximise the pressure loss.
Two wells have had plugging systems run. The first well has reduced water cut from 100% to ca. 40% and shown a significant oil rate benefit. The second well has also shown a reduced water cut (from 70% to 40%).
In developing a relief well contingency, current industry standard practice is to use a one-dimensional (1D) multiphase flow model to determine the requirements such as pump rate and mud weight to kill the blowout well. However, this does not consider certain variables. For instance, this analysis returns the same results regardless of the intercept angle of the relief well (i.e. results are identical if the relief well intercepts at a steep angle into the direction of flow, or if it intercepts at a steep angle in the same direction of flow).
A novel approach has been developed that considers the three-dimensional vector effects when a blowing out well is killed by means of a relief well intercept. This analysis offers safety and environmental benefits for well kill design and operations because it provides results which more accurately reflect the physical principles. This allows for optimization of a relief well design. For instance, this more comprehensive analysis allows the possibility to design a relief well with shallower intercept depth and lower pump requirements with the potential for an earlier kill.
This new method considers the complex interaction of the countercurrent flow that occurs at the relief well intercept and can utilize computational fluid dynamics (CFD). This enables optimization of parameters previously not considered such as specific spray design from the relief well. For instance, industry currently assumes that there is an advantage to pumping the kill fluid down the annulus of the relief well. The frictional losses are lowered (compared to pumping down the drillstring), thereby minimizng the pump requirements and maximizing the achievable rate for given pump capability. Whilst this may indeed be the case, the research covered in this paper shows that, depending on the circumstances, there can be a benefit to designing the spray pattern from the flow from the relief well at the intercept.
Various relief well kill cases were analyzed by both the standard method and the new method and the results compared. The new method predicted that relief well kills could be made with lower rates and pressures than predicted by the standard model. Using the new method offers an opportunity to increase the accuracy of relief well planning, enabling a more precise understanding of what may be achievable.
A test apparatus was designed and created to verify which of the two methods was more accurate. Physical experiments indicate that results from the proposed method match the test results closer than the standard approach.
High permeability reservoirs in Deepwater Gulf of Mexico have been completed with fracpacks resulting in high production rate wells. The initial production rates for these wells range from 3 mbd to almost 40 mbd; and these rates can be sustained over extended periods of time (several years). Most of these developments in the Gulf of Mexico require sand control with cased hole fracpacks as the preferred completion technique. In addition to providing reliable sand control, fracpacks result in relatively low skin by bypassing near wellbore damage. Over the past few years, operators have focused on reducing skin and improving the production from these wells; leading to a more detailed analysis of fracpack performance. This paper will demonstrate that in high permeability reservoirs, production from the off-plane perforations is as important as production from the fracture. It examines the theoretical basis of the contribution of off-plane perforations to total flow and demonstrates the adverse effect on this contribution due to damage from drilling fluids and solids, cementing spacers and solids, fluid loss materials, perforating debris, wellbore debris, and crosslinked gel. Several case histories are analyzed to evaluate and quantify these effects and to show that the lower the conductivity contrast between the (high permeability) reservoir and the fracture, the higher the production benefit that can be realized by effectively cleaning the off-plane perforations.
Nitrate used to control reservoir souring in oil fields contains nitrite impurities. Nitrite is a strong oxidizer, and when used in souring-treatment fluids, the flow path often includes carbon-steel piping. Vanadium, also an oxidizer, is at times found in oilfield-production streams that commingle with souring-treatment fluids. The interactions between nitrite and vanadium and their effects on carbon steel X65 corrosion were investigated.
The effect of nitrite on corrosion was investigated using synthetic brine to simulate produced water [rich in carbon dioxide (CO2), pH value of approximately 5] and seawater (negligible CO2, pH value of approximately 7). Tests were conducted with carbon steel X65 exposed to synthetic brine at 25, 60, and 80°C using a rotating cylinder electrode (RCE). The test results demonstrate the following: