Pineda, Wilson (BP) | Wadsworth, Jennifer (BP) | Halverson, Dann (BP) | Mathers, Genevive (BP) | Cedillo, Gerardo (BP) | Maeso, Carlos (Schlumberger) | Maggs, David (Schlumberger) | Watcharophat, Hathairat (Schlumberger) | Xu, Weixin (Wayne) (Schlumberger)
Deepwater depositional environments in the Gulf of Mexico can be very complex. Accurate determination of depositional facies is important in these capital-intensive fields. The most common reservoir facies are laterally extensive sheet sandstones with thin mudrock layers, channel complexes (isolated or amalgamated) and channel-levee complexes (often with poor reservoir communication). Reservoirs are often complicated by steep dips close to salt domes and the presence of potential fluid conduits due to faults or fractures. Borehole images aid in determining the character of the sediments, as well as improve net sand calculations, and illuminate the geology in the near wellbore region both in structure and depositional environment, and to provide valuable geomechanics information for the determination of the stress vector.
A well was recently drilled through one of these deep water sediment sequences in the Gulf of Mexico with an oil-based mud (OBM) system. An extensive acquisition program included a series of logging while drilling (LWD) and wireline images. In addition to the current LWD lower resolution borehole imaging tools, a new LWD dual physics OBM imager was deployed for the first time in this field. Five different types of physics were acquired, including lower-resolution images from nuclear measurements (gamma ray, density and photoelectric) and the high-resolution images from dualphysics OBM imager (DPOI) which is based on resistivity and ultrasonic measurements. Wireline high-resolution OBM resistivity images were also acquired. This paper shows a comparison of images collected with the new DPOI versus traditional LWD images and high-resolution wireline resistivity images.
Comparisons of the types of features observed from the various imaging tools were made, showing how the differences in physics, resolution and time of logging affects the images, as well as the impact these factors can have on subsequent interpretations. Four main categories of features are included in comparisons between the tools: sand-rich sections, consistently dipping mudrocks, chaotic zones and fractures/faults. The different images allow fuller interpretation of the gross sequence. In general, the higher the resolution, the more detailed and confident the interpretation is, particularly where the hole conditions are good. In degraded borehole sections, the LWD acquisition was beneficial for obtaining images as early as possible, when damage was at a minimum. The impact of the differences in the physics depends on the properties and contrasts being imaged. This is observed with fractures - both conductive and resistive examples can be seen on both LWD and wireline images. The ultrasonic images are complementary with both low and high amplitude fractures seen, providing more confidence in the fracture interpretation.
Rabinovich, Michael (BP) | Bergeron, John (BP) | Cedillo, Gerardo (BP) | Mousavi, Maryam (BP) | Pineda, Wilson (BP) | Soza, Eric (BP) | Le, Fei (Baker Hughes, a GE Company) | Maurer, Hans-Martin (Baker Hughes, a GE Company) | Mirto, Ettore (Schlumberger) | Sun, Keli (Schlumberger)
Copyright 2019 held jointly by the Society of Petrophysicists and Well Log Analysts (SPWLA) and the submitting authors. Annual Logging Symposium held in The Woodlands, TX, USA June 17-19, 2019. ABSTRACT Typically, only conventional logging while drilling (LWD) resistivity and gamma ray logs are acquired in overburden sections of deep-water wells. Very important decisions impacting drilling safety and borehole stability must be made based on correct and timely interpretation of these logs. Drilling-induced fractures, faults, and eccentricity effects in large holes drilled with oil-based mud are common reasons for anomalous responses of LWD resistivity tools in overburden sections. These anomalies are often associated with fluid losses and other drilling hazards such as borehole assembly sticking. With the limited number of real-time (RT) measurements even if the optimal minimal set of RT curves is selected, the interpretation of these anomalies is challenging. Drilling-induced fractures can be misinterpreted as eccentricity or even as a permeable zone with resistive invasion in water sands or with a hydrocarbon-bearing layer, which is especially important for proper casing and cementing decisions. Resistivity modelling is an irreplaceable tool that enables us to uniquely identify the cause of each anomaly. Time-lapse measurements also help to recognize and identify the causes of anomalies as borehole conditions change with time. Fractures can become deeper with continued overbalance or healed with lost-circulation material or a reduction of equivalent circulating density. Washouts typically enlarge with time and after reaming. We present several case studies from deep-water wells in the Gulf of Mexico illustrating typical LWD resistivity anomalies in overburden sections. The examples include fault identification and borehole events such as fluid losses, borehole enlargement, and gas-bearing intervals. The challenges of interpreting each anomaly and the necessity of the appropriate LWD resistivity modeling kit are clearly demonstrated. Many of the examples illustrate the advantages of measuring after drilling (MAD pass) logs. INTRODUCTION When drilling overburden sections in deep water wells, the hole diameters are big, open hole sections are long and, typically, the LWD suite is limited to conventional resistivity and gamma ray (GR) logs. Additionally, the limited number of real-time (RT) resistivity curves makes the unique interpretation of resistivity data difficult.
Engineers need to predict the production characteristics from hydraulically fractured wells in tight gas fields. Decline curve analysis (DCA) has been widely used over many years in conventional oil and gas fields. It is often applied to tight gas, but there is uncertainty regarding the period of production data needed for accurate prediction.
In this paper decline curve analysis of simulated production data from models of hydraulically fractured wells is used to to develop improved methods for calibrating decline curve parameters from production data. The well models were constructed using data from the Khazzan field in Oman. The impact of layering, permeability and drainage area on well performance is also investigated. The contribution of each layer to recovery and the mechanisms controlling that contribution is explored.
The investigation shows that increasing the amount of production data used to fit a hyperbolic decline curve does not improve predictions of recovery unless that data comes from many years (20 years for a 1mD reservoir) of production. This is because there is a long period of transient flow in tight gas reservoirs that biases the fitting and results in incorrect predictions of late time performance. Better predictions can be made by estimating the time at which boundary dominated flow is first observed (tb), omitting the preceding transient data and fitting the decline curve to a shorter interval of data starting at tb. For single layer cases, tb can be estimated analytically using the permeability, porosity, compressibility and length scale of the drainage volume associated with the well. Alternatively, tb can be determined from the production data allowing improved prediction of performance from 2-layer reservoirs provided that a) there is high cross-flow or b) there is no cross-flow and the lower permeability layer either does not experience BDF during the field life time or it is established quickly.
Essam, Wael (BP) | Scarborough, Christopher (BP) | Wilson, Nick (BP) | Shimi, Ahmed (BP) | Santos, Helio (Safekick) | Hannam, Jason (Safekick) | Catak, Erdem (Safekick) | Lancaster, Jay (Seadrill) | Gooding, Neil (Seadrill) | Baan, Robert (Seadrill)
BP had long recognized the benefits of MPD, having been using it for years to deliver very challenging wells in Egypt, Trinidad and the North Sea; and it was time to bring these benefits to its GoM operations. Once the company team identified a portfolio of suitable candidate wells to allow the economics of the application to be advantageous, they partnered with Seadrill to provide the MPD service integrated into the West Capricorn drilling rig. This approach builds on synergies within the drilling contractor organization to achieve long term economic, competency, and risk management benefits, resulting from integrating this drilling method on the rig, and eliminating interfaces with 3rd party providers. The paper will discuss how the company and the drilling contractor teams, together with equipment suppliers and training providers, managed the project from initial system design, to installation and commissioning, to the successful delivery of the first well using MPD, at top quartile performance. It will discuss the process for optimizing the design and testing it from a reliability and process safety perspectives; engaging the regulatory authority and the classification society; integrating MPD in the well planning process and developing operational procedures for use on the rig; and delivering a training program for the wider team covering the technical and the human factors aspects to ensure a successful delivery.
Hadiaman, Farid (BP) | Mollayev, Samir (BP) | Huseynzade, Nijat (BP) | Valiyev, Ziya (BP) | Gracia, Jesse (BP) | Galvan Amaya, Jeanine (BP) | Fulks, Jeff (BiSN) | Rahimov, Khalid (Baker Hughes GE) | Pinero, Luis (Baker Hughes GE) | Ruzmetova, Sitora (Baker Hughes GE)
Thru-tubing uphole re-completion is a workover technique aiming to re-complete the existing wellbore by abandoning the lower producing zone and subsequently perforate upper layer. There are various techniques used to abandon the lower zone worldwide. Specific to Caspian Sea development, the abandonment will only be required to set an isolation plug. However, statistically speaking, success ratio of lower zone abandonment, is quite low using current plugs set in different condition of completion. In addition, the risk of deploying balance cement plug also presents significant challenge due to interval limitation between top of the cement and new perforation interval. It is deemed necessary to find a fit-for purpose solution that provides a solution to the Caspian Sea environment plug and abandonment strategy. A new plug technology, metal to metal system, was introduced to provide assurance isolating the lower zone prior to perforating new upper zone. Subsequently, a wireline deployed or pipe (tubing) conveyed perforation is not an attractive solution to thru-tubing up-hole recompletion technique. A new technology to perforate lively is selected from safety and economic point of view for this specific well. The perforation was done in underbalance condition with intelligent coiled tubing. The uphole re-completion (well delivery) performance was more attractive than other conventional uphole re-completion techniques. This paper will elaborate the success of recompletion techniques by deploying multiple new technologies in the Caspian Sea.
Tavassoli, Shayan (The University of Texas at Austin) | Shafiei, Mohammadreza (The University of Texas at Austin) | Minnig, Christian (swisstopo) | Gisiger, Jocelyn (Solexperts) | Rösli, Ursula (Solexperts) | Patterson, James (ETHZ) | Theurillat, Thierry (swisstopo) | Mejia, Lucas (The University of Texas at Austin) | Goodman, Harvey (Chevron ETC) | Espie, Tony (BP) | Balhoff, Matthew (The University of Texas at Austin)
Wellbore integrity is a critical subject in oil and gas production, and CO2 storage. Successful subsurface deposition of various fluids, such as CO2, depends on the integrity of the storage site. In a storage site, injection wells and pre-existing wells might leak due to over-pressurization, mechanical/chemical degradation, and/or a poor cement job, thus reducing the sealing capacity of the site. Wells that leak due to microannuli or cement fractures on the order of microns are difficult to seal with typical workover techniques. We tested a novel polymer gelant, originally developed for near borehole isolation, in a pilot experiment at Mont Terri, Switzerland to evaluate its performance in the aforementioned scenario.
The polymer gel sealant was injected to seal a leaky wellbore drilled in the Opalinus Clay as a pilot test. The success of the pH-triggered polymer gel (sealant) in sealing cement fractures was previously demonstrated in laboratory coreflood experiments (
The novel sealant was successfully deployed to seal the small aperture pathways of the borehole at the pilot test. We conducted performance tests using formation brine and CO2 gas to put differential pressure on the polymer gel seal. Pressure and flow rate at the specific interval were monitored during and after injection of brine and CO2. Results of performance tests after polymer injection were compared against those in the absence of the sealant.
Several short-term (4 min) constant-pressure tests at different pressure levels were performed using formation brine, and no significant injection flow rate (rates were below 0.3 ml/min) was observed. The result shows more than a ten-fold drop in the injection rate compared to the case without the sealant. The polymer gel showed compressible behavior at the beginning of the short-term performance tests. Our long-term (1-week) test shows even less injectivity (~0.15 ml/min) after polymer gelation. The CO2 performance test shows only 3 bar pressure dissipation overnight after injection compared to abrupt loss of CO2 pressure in the absence of polymer gel. Sealant shows good performance even in the presence of CO2 gas with high diffusivity and acidity.
Pilot test of our novel sealant proves its competency to mitigate wellbore leakage through fractured cement or debonded microannuli, where other remedy techniques are seldom effective. The effectiveness of the sealing process was successfully tested in the high-alkaline wellbore environment of formation brine in contact with cement. The results to date are encouraging and will be further analyzed once over-coring of the wellbore containing the cemented annulus occurs. The results are useful to understand the complexities of cement/wellbore interface and adjust the sealant/process to sustain the dynamic geochemical environment of the wellbore.
Altemeemi, Bashayer (KOC) | Gonzalez, Fabio (BP) | Al-Nasheet, Anwar (KOC) | Gonzalez, Doris (BP) | Al-Shammari, Asrar (KOC) | Sinha, Satyendra (KOC) | Muhammad, Yaser (Schlumberger) | Datta, Kalyan (KOC) | Al-Mahmeed, Fatma (KOC)
Sound development plans are based on complex 3-D 3-Phase multimillion grid reservoir simulation models. These models are used to run different scenarios where probability distributions are included to understand the impact of uncertainties and mitigate main risks that could raise during the life of the field. With today's available dominant supercomputers, reservoir engineers have the tendency to undervalue the power of classical reservoir engineering. However, in a fully connected reservoir tank that honors the basis of the material balance equation, material balance technique has been long recognized as a powerful tool for interpreting and predicting reservoir performance by estimating initial hydrocarbon in place and ultimate hydrocarbon recovery under various depletion scenarios. In brief, under the right conditions, material balance technique is a suitable tool for field development planning. The power of material balance to predict long term performance is undisputable, especially in the case of a prevailing uncertainty. This is the case of the Magwa-Marrat field, where the development plan has historically been driven by the potential risk of asphaltene deposition in the reservoir.
The objective of this paper is to show a step by step process to integrate data to build a reliable model using material balance and how this model is utilized to progress a field development plan capable of managing uncertainty and provide the tools to mitigate risk.
Pressure data is obtained from repeat formation tester (RFT), static data from shut-in pressures and reservoir superposition pressures from pressure transient analysis. The average reservoir fluids properties are retrieved from a compositional equation of state based on circa 20 PVT studies.
The material balance model was successfully completed, and the resulting stock tank oil initially in place (STOOP) was compared to volumetric calculations. Solution gas, rock compaction and aquifer influx were determined as drive mechanisms. The Campbell Plot, diagnostic tool, was proven to be prevailing defining early energy to determine STOOIP and the aquifer properties were calculated by matching the distal energy
The material balance model was then used to run different development strategies. This methodology captured the impact of depleting the reservoir down to Asphaltene Onset Pressure (AOP) as well as below AOP. The model was also used to define the requirements for water injection rates and startup of a water flooding project for pressure support. Additionally, the material balance work was implemented to support reservoir management and to maximize recovery factor.
This paper presents an innovative approach of integrating asphaltene behavior from laboratory tests and fluid studies, combined with material balance to screen development scenarios for an efficient depletion plan including water injection to manage asphaltene risks and optimize ultimate recovery. Finally, a fully ground-breaking strategy, not reported earlier to the knowledge of the authors, has been established to manage the perceived main risk in the Magwa-Marrat reservoir.
The advantages of measuring gravity in the borehole environment have been well established in the literature and through first-generation instruments. These measurements can be very effective for directly imaging mass distributions at-depth in the subsurface and at large-distances from well bores. To date, a breakthrough has been limited by the sensor form factor (size) and measurement stabilization. Newly emerging MEMS three-axis microgravity technology, deployable by wireline, is showing the potential for a host of applications and capable of realizing the long-coveted advantages. For reservoir surveillance, a primary application is to perform more pro-active, frequent flood front monitoring. With its large volume of investigation, the proposed three-axis borehole gravity measurements would complement as well as fill the existing gap between traditional methods such as Pulsed Neutron and 4D seismic. Further applications extend to saturation monitoring, by-passed pay, and thin-bed identification.
In conjunction with a collaborative program to develop a three-axis gravity sensor that is now being incorporated into a 54-mm diameter wireline tool with a targeted sensitivity ≈5 μGal (microGal), we have carried out extensive numerical studies to understand the signal strengths in such measurements produced by the dynamic processes in different types of reservoirs, and demonstrate the capabilities and limitations of borehole gravity and its potential use within a revised reservoir surveillance plan.
We show examples of forward modelling data from reservoirs with varying fluid displacement mechanisms. Reservoir porosity and saturation data are used to model the predicted three-component (i.e., vector) gravity anomaly (gz, gx, and gy) responses along the wellbore in a variety of wells as the fluid-water front progresses through the field. The modelling included both producing wells and injector wells. The paper will present a description of a forward modeling workflow, simulation studies based on real reservoir data, and the validating measurements.
The paper examines the results of the forward modelling and compares the results with the sensitivity of the new three-axis borehole gravity sensor. The results will show that a wireline deployed three-axis gravity tool with a targeted noise floor of ≈5 μGal will provide additional important surveillance to constrain reservoir models as well as provide vital information to help reduce uncertainty when actively managing waterfront movement (sweep) and secondary recovery and detecting early breakthrough of water; and for monitoring and adjusting strategy when producing through reservoir depressurization. The described workflow is seen as very important for any future survey planning to understand the time-lapse gravity signal and the feasibility of time-lapse gravity surveillance under different reservoir conditions.
A three-axis borehole gravity tool with a form factor enabling it to be deployed through cased hole and into deviated and horizontal wells is completely novel and has not been presented previously. A workflow that understands survey feasibility and optimal survey-time intervals is novel. A systematic and comparative study of three-axis borehole gravity responses through modelling of a reservoir is novel and has limited previous work.
Al-Obaidli, Asmaa (KOC) | Al-Nasheet, Anwar (KOC) | Snasiri, Fatemah (KOC) | Al-Shammari, Obaid (KOC) | Al-Shammari, Asrar (KOC) | Sinha, Satyendra (KOC) | Amjad, Yaser Muhammad (Schlumberger) | Gonzalez, Doris (BP) | Gonzalez, Fabio (BP)
The Magwa-Marrat field started production early 1984 with an initial reservoir pressure of 9,600 psia Thirtysix (36) producer wells have been drilled until now. By 1999, when the field had accumulated 92 MMSTB of produced oil and the reservoir pressure had declined to 8000 psia, the field was shut-in until late 2003 due to concerns on asphaltene deposition in the reservoir that could cause irreversible damage and total recovery losses. The field was restarted in 2003 an it has been in production since then. By April 2018 the field had produced 220 MMSTBO, with the average reservoir pressure declined to 6,400 psia. As crude oil has been produced and the energy of the reservoir has depleted, the equilibrium of its fluid components has been disturbed and asphaltenes have precipitated out of the liquid phase and deposited in the production tubing. There is a concern that the reservoir will encounter asphaltene problems as the reservoir pressure drops further. The objective of this manuscript is to present the process to understand the reservoir fluids behavior as it relates to asphaltenes issues and develop a work frame to recognize and mitigate the risk of plugging the reservoir rock due to asphaltenes deposition with the end purpose of maximizing recovery while producing at the maximum field potential Data acquired during more than 30 years have been integrated and analyzed including 22 AOP measurements using gravimetric and solid detection system techniques, 17 PVT lab reports, 1 core-flooding study and 1 permeability/wettability study. Despite the wide range of AOP measured in different labs, it was possible to determine that the AOP for the Magwa-Marrat fluid is 5,600 500 psia and the saturation pressure is 3,200 200 psia. Results of this fluids review study indicates that it might be possible to deplete the reservoir pressure below the AOP while producing at high rates.
This paper covers the development of a key component of an internal system to report invisible lost time (ILT) metrics across drilling operations. Specifically this paper covers the development of a generalizable rig state engine based on the application of supervised machine learning. The same steps used in the creation of the production rig state engine are appled here to a smaller data set to demonstrate both the tractability of the problem and the methods used to create the rig state engine in the production system.
The project objective was to provide efficiency and engineering metrics in a central repository covering operated regions. The system is designed to require minimal user configuration and management and provides both historic and near real time analysis to deliver a rich resource for offset comparison and benchmarking.
Identifying rig-state is at the heart of every performance and engineering analysis system. This can be thought of as a machine learning classification problem. A large supervised learning set was constructed and used to train classification models which were compared for accuracy. A key success metric was the ability to generalise the selected model across different operations. Output from the rig-state classifier was then used to derive KPI data which was presented through a web based front end. A pilot system was then developed using agile principles allowing for rapid user engagement. Testing demonstrated that the system can support all real time operations within the company simultaneously and rapidly process historic well data for offset benchmarking. The cloud-based architecture allows rapid deployment of the system to new groups significantly reducing deployment costs. The system provides a foundation for onward data science and more advanced functionality.
Minimal configuration, cloud storage and processing, combining contextual data with real-time rig data, near-real-time and historic analysis capabilities, rapid deployment, low cost, high accuracy and consistent metrics are all key and proven value drivers for the system. The output data is aso a valuable resource for additional machine learning and data science projects.