Du, Xuan (Research Institute of Petroleum Exploration & Development, PetroChina Co. Ltd.) | Zheng, Haora (Research Institute of Petroleum Exploration & Development, PetroChina Co. Ltd.) | Wang, Xiaochun (Research Institute of Petroleum Exploration & Development, PetroChina Co. Ltd.) | Hua, Xin (China Petroleum Technology Development Corporation, PetroChina Co. Ltd.) | Guan, Wenlong (Research Institute of Petroleum Exploration & Development, PetroChina Co. Ltd.) | Zhao, Fang (Research Institute of Petroleum Exploration & Development, PetroChina Co. Ltd.) | Xu, Jiacheng (Research Institute of Petroleum Exploration & Development, PetroChina Co. Ltd.)
Heavy oil reservoirs are generally unconsolidated and easy to produce sand during production
Khedr, Sherine (BP Exploration Operating Co) | El-dabi, Fady (BP Exploration Operating Co) | Nashaat, Mohamed (BP Exploration Operating Co) | Mohiuldin, Ghulam (BP Exploration Operating Co) | Galal, Alaa (BP Exploration Operating Co) | Slim, Teddy (BP Exploration Operating Co) | Hughes, Andrea (BP Exploration Operating Co) | Morris, Lyndsay (BP Exploration Operating Co) | Ramsay, David (BP Exploration Operating Co) | El-wakeel, Wael (BP Exploration Operating Co) | Mubarak, Hussein (BP Exploration Operating Co) | Smith, Jeffrey (BP Exploration Operating Co) | Munger, Robert (BP Exploration Operating Co)
Giza Fayoum Completions was the second campaign of the West Nile Delta project. The campaign consisted of eight cased-hole gravel pack subsea wells. The Giza Fayoum campaign was sanctioned in August 2017 with an execution start date five months later. In this time, the well designs were finalized, downhole completion equipment manufactured, and the execution plan approved. A high rate water pack sand control technique was designed to deliver an estimated production rate of 120 MMscf/d / well. It was planned to deliver eight wells over a period of 5 months from Q1 2018 giving an average of two and a half weeks per well. Seven of the eight wells were cleaned up through a large bore completion landing string system. Each well was flowed to high rate temporary well test equipment installed on the DP semi-submersible rig to a gas rate of 65 MMscf/d, with PLT logs conducted.
This successful, fast-paced campaign is the result of applying lessons learned from the former campaign; Taurus Libra and identifying additional efficiencies that would improve performance. The design similarities between the two campaigns permitted the team to extend the learning curve and deliver superb performance on Giza Fayoum.
As for safety performance, the campaign was delivered without any lost time incident. A rigorous approach to continuous improvement resulted in reducing the completion time to 12 days per well (not including rig move, de-suspension and suspension activities). The optimized bean up procedures supported by PLT data made it possible to reduce greenhouse emissions by 20%. The sand control technique resulted in a significant reduction of total skins. Moreover, the team succeeded in delivering the wells safely, ahead of plan and under budget while adhering to BP's overarching strategy of delivering safe, compliant and reliable wells.
The efficiencies, safety culture and technology used during this campaign are now being set as the standard for future campaigns in Egypt and beyond.
This paper demonstrates how 280ft of oil column spread unevenly across multiple and differentially depleted reservoir units separated by shale layers of varying thicknesses in a highly deviated (62 deg.) well was perforated in a one trip system and how the project cost was minimized by achieving multiple perforations in a single trip whilst retaining capacity to effectively cure losses and mitigating post-perforation well control risks. Against the conventional perforation methodology where reservoir units are perforated individually, isolated before carrying out the next perforation in the subsequent reservoir. The one trip system was designed and deployed in one run targeting all the 6 separate carefully selected sand lobes in one run ensuring good standoff from the contact and zonal isolation behind casing. Successful execution was confirmed with all the expected physical outcomes which includes pipe vibration, brine loss as well as inspection of the spent guns. A post perforation noise and production logging also confirmed flow across all planned perforation intervals. Perforation of a highly deviated well in differentially depleted multi-lobed reservoirs present significant operational risks. This paper illustrates how one can safely collapse multiple conventional perforation runs into a single trip with its attendant benefits on cost efficiency, crossflow and well control. This is the first of its kind in the Niger Delta.
Optical fiber flatpacks, which are cable-reinforced plastic-encased fiber bundles used for local temperature and acoustic measurements, can be stressed when near a perforating gun. The fiber itself is floated in metal tubes with gel. Understanding the behavior under severe shock causes the use of potential mitigation schemes. In this work, the flatpack containing optic fibers is simulated for survivability on the casing of a perforating gun system. Using a shock hydrocode in two-dimensions (2D), a flatpack is simulated on the 5 1/2-in. casing of a 3 3/8-in. gun with a 21-g shaped charge. Effects of concrete encasement, clamps, and off-angle shots are considered. The view is in the plane of one shaped charge.
Quantitative results include pressure temporal profiles, velocity profiles, and g acceleration at the fibers. Pressure at the flatpack peak is in the hundreds to thousands of psi, and accelerations peak in the hundreds to thousands of g. Unconfined flatpacks tend to launch from the casing, while confined flatpacks tend to oscillate at their location. Pressure contour models show the shaped charge breaking into multiple pressure pulses. The primary shocks are in front of and behind the charge. Secondary pulses occur off-axis near the base of the charge and from the jet bow shock near the top of the charge. Overall comparative simulation results indicate optimum flatpack location and configuration. Novel mitigation schemes are identified and simulated. A fiber-optic flatpack has been simulated in a zero- degree loaded gun for the first time; this information helped with understanding survivability against shaped charge shocks.
Faster production declines than initially forecast were observed in numerous deep-water assets. These wells were completed as Cased Hole Frac-Pack (CHFP) completions (
Seven key damage mechanisms were identified as forming the basis for PI degradation: 1) off-plane perforation stability, 2) fines migration, 3) fracture conductivity, 4) fracture connectivity, 5) fluid invasion, 6) non-Darcy flow and 7) creep effects. A near wellbore production model incorporating the completion, fracture geometry and reservoir is coupled with a geomechanics model to assess each mechanism. A Design of Experiment setup varies the input ranges associated with each of the seven damage mechanisms. Input parameters for the model are risked and rely on ranges from standard and newly developed well and lab tests. The model assesses well performance and driving mechanisms at different points in time within the production life.
Primarily the study focused on high permeability and highly over pressured reservoirs. For the types of wells/fields assessed in the study, the results indicated three phases of decline based on the interaction between the formation properties, the completion components and the operating parameters. The three phases breakdown into: (1) a pre-rock failure stage where declines are relatively small, (2) an ongoing rock failure stage where declines are rapid and (3) a post failure stage where declines are again moderate. In each of these stages different parameters and damage mechanisms were assessed to be impactful. The workflow was also utilized to match pre and post acidizing treatments. A comparison for varying rock types was included looking at the impact of rock strength and formation permeability on the ranking of the damage mechanisms. The impact of operating parameters such as drawdown can also be assessed with the tool showing that increased drawdowns may not always be beneficial to the long-term production of the well.
The paper presents the underlying drivers for PI Decline for deep-water assets of a specific attribute set. Through accurate representation of reservoir and completion, the workflow highlights the impact and combined impact of different damage mechanisms. The paper also shows a direct link between the mechanical properties (moduli and strength) and boundary conditions (pore pressure and stress) and the well performance and productivity. The workflow provides a methodology by which lab and field tests can be transformed into assessments of future well performance without strictly relying on analogs that may or may not be appropriate.
Rivero, Jose A. (Schlumberger Canada Limited) | Faskhoodi, Majid M. (Schlumberger Canada Limited) | Mukisa, Herman (Schlumberger Canada Limited) | Zaluski, Wade (Schlumberger Canada Limited) | Ali Lahmar, Hakima (Schlumberger Canada Limited) | Andjelkovic, Dragan (Schlumberger Canada Limited) | Xu, Cindy (Schlumberger Canada Limited) | Ibelegbu, Charles (Schlumberger Canada Limited) | Kadir, Hanatu (Schlumberger Canada Limited) | Sawchuk, William M. (Pulse Oil) | Pearson, Warren (Pulse Oil) | Ameuri, Raouf (Schlumberger Canada Limited) | Gurpinar, Omer (Schlumberger)
The Bigoray area of the Pembina field in western Alberta consists of approximately 50 naturally-fractured Nisku carbonate reefs. Production from the Bigoray Nisku D and E Pools started in 1978, and shortly after, water injection was initiated to maintain reservoir pressure as a secondary drive mechanism. By 2013, the pools had reached high water-cuts, making them uneconomical to produce. In 2017, a decision was made to reactivate the pools and initiate a solvent injection Enhanced Oil Recovery (EOR) project feasibility assessment.
A multi-disciplinary team was assembled to review and reinterpret all the geoscience data with modern methodologies to characterize the reservoirs and create new static model descriptions to be used in a dynamic model. Data from well logs, seismic, core measurements and image logs was integrated into a comprehensive and consistent model that could be used with certainty as a prediction tool.
A history-matching process was carried out by creating different realizations of the static model to honor well-to-well connectivity and water movement within the pools. The history-matching process was performed while ensuring that the model updates were global in nature and consistent with the geological understanding of the reservoirs.
The history-matched model was used to optimize the location of new producers and injectors based on remaining oil saturations and reservoir structure. Optimization of the EOR scheme involved testing a matrix of scenarios to investigate the effect of injection rates, solvent volumes as well as production pressures and voidage ratios. Additionally, in an effort to improve displacement efficiency, a large number of simulation runs were devoted to test and establish the most efficient locations for the well perforations in both the new injectors and producers.
Approximately 20% of all oilwells in the world use a beam pump to raise crude oil to the surface. The proper maintenance of these pumps is thus an important issue in oilfield operations. We wish to know, preferably before the failure, what is wrong with the pump. Maintenance issues on the downhole part of a beam pump can be reliably diagnosed from a plot of the displacement and load on the traveling valve; a diagram known as a dynamometer card. We demonstrate in this paper that this analysis can be fully automated using machine learning techniques that teach themselves to recognize various classes of damage in advance of the failure. We use a dataset of of 35292 sample cards drawn from 299 beam pumps in the Bahrain oilfield. We can detect 11 different damage classes from each other and from the normal class with an accuracy of 99.9%. This high accuracy makes it possible to automatically diagnose beam pumps in realtime and for the maintenance crew to focus on fixing pumps instead of monitoring them, which increases overall oil yield and decreases environmental impact.
Use of diverters for altering fluid distribution among created hydraulic fractures in horizontal wells has gained popularity in recent years, both for initial and re-fracturing treatments. Aims in initial fracturing treatments have included creating more uniform distribution of slurry within the created fractures, increasing stage efficiency by reducing the number of pumping stages while increasing the number of clusters per stage, increasing the number of fractures created in openhole completions, reducing interactions between fractures in adjacent horizontal wells, etc. In re-fracturing treatments, a popular application is for altering fluid distribution in wells re-treated without isolation between stages (Pump & Pray/Bullheading) with the intent of increasing the number of re-activated fractures and initiating new fractures through added perforations.
Engineering analysis of the mechanics of fluid diversion has not received the same degree of attention as its use. The reported discussions are often limited in their scope, two-dimensional in structure, and somewhat speculative in their conclusions.
This paper divides the targets of diversion into three categories; at the wellbore/perfs, near wellbore, and deeper inside the fracture. It divides the types of diverters into three categories, mechanical, solid particulate (including proppants), and chemical. The applications are divided into two categories, initial and re-fracturing, together with highlighting their differences and requirements for successful diversion. The paper discusses how presence of proppant changes the fluid distribution in favor of more conductive perforations. It considers the fracture as a three-dimensional structure, extending on both sides of the wellbore. It describes how different diverting agents cause fluid redistribution between the fractures, and the important role of proppant in some applications. It shows that as the target of fluid diversion moves away from the wellbore the chances of its success become smaller and more unpredictable, while also the time before effective diversion takes place becomes longer.
Comprehensive understanding of the mechanics of fluid diversion helps in the selection of the type of diverter and how best to deploy it for achieving specific objectives and results.
Schnitzler, Eduardo (Petrobras) | Ferreira Gonçalez, Luciano (Petrobras) | Savoldi Roman, Roger (Petrobras) | Atanásio Santos da Silva Filho, Djalma (Petrobras) | Marques, Marcello (Petrobras) | Corona Esquassante, Ricardo (Petrobras) | Denadai, Nilson José (Petrobras) | Feliciano da Silva, Manoel (Petrobras) | Rosas Gutterres, Fábio (Petrobras) | Signorini Gozzi, Danilo (Petrobras)
Pre-salt heterogeneous carbonate reservoirs typically present long net pays, high production/injection rates and some flow assurance risks. This paper presents general information, results and lessons learned regarding the installation of Intelligent Well Completion (IWC) in Santos Basin Pre-Salt Cluster (SBPSC) wells. It also presents some important improvements to be introduced in the future IWC systems specification and qualification based on the lessons learnt in these projects, setting some new challenges to the industry.
The benefits expected with the use of IWC are achieved at the expense of challenging well engineering, since well completion design becomes more complex and well construction risks increase. Detailed and integrated planning is essential for the success of the operations, starting at the earliest phases of the well design and continued through detailed execution plans. The use of standardized practices and procedures has led to significant increases on installation performance. On the other hand, an open mind and a constant search for improvements allowed new solutions and procedures to be developed throughout the years. Regarding the system integration, a flexible and standardized control architecture was developed to allow combining different IWC providers and subsea vendors, which proved to be a successful approach.
The most important improvement in IWC installation was the anticipation of the acid stimulation, nowadays performed before the vertical Wet Christmas Tree (WCT) installation. In order to achieve this goal some crucial improvements were gradually implemented in the stimulation practices, such as, an initial injectivity increase solution and some new acid diversion solutions, which allowed eliminating the use of coiled tubing and, as a consequence, the need of a subsea test tree. The well design team conducted an integrated risk assessment to properly evaluate the new practices and establish some actions to reduce the risks. Intense communication between production zones was observed during the acid job in some of the initial wells, ruining the gains of the IWC. After a comprehensive analysis, some possible causes were identified and with the new stimulation practices this issue was eliminated.
Over the years, with the introduction of several improvements, some of them presented in this paper, the well completion duration was reduced to less than 50% of the one observed in the initial wells. This major performance increase has been essential to keep this deepwater projects feasible, especially in the oil scenario seen in recent years. Some of the new practices and lessons learned in this 100 wells equipped with IWC has set groundbreaking practices for Brazilian pre-salt fields development and may stand as a reference for the industry in similar deepwater projects. Additional requirements for future systems are expected to improve even further the performance in this scenario.
Maximizing economic performance in shale requires optimal selection of well and cluster spacing, among other parameters. Reservoir engineering calculations can be used to optimize spacing, but these calculations are impacted by uncertainties in input parameters. System permeability is particularly important and difficult to measure. Diagnostic Fracture Injection Tests (DFIT’s) are often used to estimate permeability because they provide a direct, in-situ measurement. However, in recent work, it was shown that conventional DFIT interpretation techniques can overestimate permeability in gas shale by two orders of magnitude. In this study, the impact of the permeability estimate is demonstrated using a dataset from the Utica/Point Pleasant. Production data is history matched with models assuming high and low permeability. It is possible to history match both models because of non-uniqueness between fracture area and permeability. Sensitivity analysis simulations are performed to assess the impact of well and cluster spacing on net present value. Relative to the high permeability model, the low permeability model has a greater optimal well spacing and a tighter optimal cluster spacing. The comparison shows that improved accuracy in the permeability estimate significantly improves economic performance. The low permeability model has much earlier production interference than the high permeability model because the low permeability model requires greater effective fracture length to match production. This is consistent with the operator’s experience that outer wells outproduce inner wells within weeks or months from the start of production.