Game Changer in Dealing With Hard Scale Using a Slickline Torque Action Debris Breaker

Scale deposition is a major concern in Gulf of Suez Fields, variations in water composition and operating conditions resulted in the deposition of full spectrum of scale depositions in different fields. The common practice in GOS is to prevent scale deposition by periodical scale inhibition treatment. However the field experience showed variation in efficiency of inhibition under different operating conditions which results in some cases in scale deposition. In this case we are obliged to react and do intervention to clean out these wells either with chemical dissolution or coiled tubing clean out which is sometimes becomes costly and stand clueless in front of hard scale. Typically, in offshore operating fields, rig-less solutions is the optimum. A simple, innovative, and cost effective Torque action debris breaker tool is a new rig-less solution deployed on slick-line unit. The tool can be run at different sizes to allow for optimum scale removal. Activation is achieved via downward jarring action. The TADB tool applies a new operating concept different from milling. The tool consists of a sharp knife with a broach body. The operating mechanism uses the jarring down action in order to apply jackhammer force on the scale accumulation, which allows decreasing the bond between different layers of scale and between the scale and tubing. Another advantage is having the knife rotating after each jar action, which allows this force to be applied on different positions of scale accumulation adding more efficiency. The tool was first deployed in Egypt in one of the challenging oil wells offshore gulf of suez, which has a historical scale deposition issues "mainly hard deposition of zinc & lead sulfides". several trials were performed to clean out the well historically using coiled tubing operations using barge assist, it took 2 months of operation to achieve partial success & the well was worked over later. The Torque Action debris breaker was tried against the same scale type and found successful. allowing the well to be drifted with 2.7" compared with 2.25" before the job. The operation cost is by no means comparable to the previous cost of coiled tubing operations. Following this wells three other wells were intervened using the same tool and showed much better progress of scale clean out in comparison with other slick-line tools & historical coiled tubing performance in these wells. The implementation of this technology has generally optimized operating cost compared to lengthy and costly CT/WO operation minimizing footprint, equipment, manpower, job duration, and provide a more environmentally friendly solution.

Novel Mineral Scale Deposition Model Under Different Flow Conditions with or Without Scale Inhibitors

Mineral scale formation causes billions of dollars’ loss every year due to production losses and facility damages in the oil and gas industry. Accurate predictions of when, where, how much, and how fast scale will deposit in the production system and how much scale inhibitor is needed are critical for scale management. Unfortunately, there is not a sophisticated scale deposition model available, potentially due to the challenges below. First, an accurate thermodynamic model is not widely available to predict scale potential at extensive ranges of temperature, pressure, and brine compositions occurring in the oilfield. Second, due to the complex oilfield operation conditions with large variations of water, oil and gas flow rates, tubing size, surface roughness, etc., wide ranges of flow patterns and regimes can occur in the field and need to be covered in the deposition model. Third, how scale inhibitors impact the mineral deposition process is not fully understood. The objective of this study is to overcome these challenges and develop a model to predict mineral deposition at different flow conditions with or without scale inhibitors. Specifically, after decades of efforts, our group has developed one of the most accurate and widely used thermodynamic model, which was adopted in this new deposition model to predict scale potential up to 250 °C, 1,500 bars, and 6 mol/kg H2O ionic strength. In addition, the mass transfer coefficients were simulated from laminar (Re < 2300) to turbulent (Re > 3,100) flow regimes, as well as the transitional flow regimes (2300 < Re < 3,100) which occur occasionally in the oilfield using sophisticated flow dynamics models. More importantly, the new deposition model also incorporates the impacts of scale inhibitors on scale deposition which was tested and quantified with Langmuir-type kink site adsorption isotherm. The minimum inhibitor dosage required can be predicted at required protection time or maximum deposition thickness rate. This model also includes the impacts of entry-region flow regime in laminar flow, surface roughness, and laminar sublayer stability under turbulent flow. The new mineral scale deposition model was validated by our laminar tubing flow deposition experiments for barite and calcite with or without scale inhibitors and laminar-to-turbulent flow experiments in literature. The good match between experimental result and model predictions show the validity of our new model. This new mineral scale deposition model is the first sophisticated model available in the oil and gas industry that can predict mineral scale deposition in the complex oilfield conditions with and without scale inhibitors. This new mineral scale deposition model will be a useful and practical tool for oilfield scale control.

Developments on Metal Sulfide Scale Management in Oil and Gas Production

Metal sulfide scaling issue in the oil and gas production continue to present significant flow assurance challenge. Recently, a novel polymeric chemistry that can effectively control FeS scale deposition in oil and gas production system was reported. However, how to manage finely dispersed FeS particulates at surface disposal facilities and whether this polymer is capable of mitigating ZnS and PbS deposition is largely unknown. Therefore, this study continues to seek an efficient treatment option for metal sulfide scale management. Static bottle tests and dynamic scale loop tests under anoxic conditions were conducted to understand the efficacy of the novel polymeric chemistry towards metal sulfide scaling control. To mimic various field conditions; individual metal sulfide (FeS, ZnS and PbS) as well as mixed scaling scenarios were simulated. Various coagulant and oxidant chemistries were tested to understand the impact of the upstream treatment on safe disposal of FeS nanoparticles at surface facilities. This novel polymeric chemistry was found to be not only effective towards FeS scaling control, but also towards dispersion of ZnS and PbS as well. The primary mechanism of metal sulfide scale deposition control is identified to be crystal growth inhibition and crystal surface modification. Laboratory test results indicated no negative impact of new chemistry on the performance of other chemicals (coagulant, oxidizer etc.). In fact, an enhanced efficiency of iron sulfide oxidation was observed possibly due to the large surface area of finely dispersed particles. A field throughput study results indicated superior performance compared to that of various incumbent chemistries. Based on the laboratory results, it is anticipated that this chemistry will provide a new treatment option for metal sulfide scaling/deposition control. Additionally, the new chemistry did not leave any negative footprint for safe disposal of metal sulfide particulate at surface. As opposed to the calcite/barite scale, nucleation inhibition of metal sulfide may not be desired as the dissolved sulfide may cause further corrosion/deposition downstream. Therefore, the value this paper brings to the management of metal sulfides is a systematic testing and evaluation approach which confirms dispersion rather than nucleation inhibition is effective control mechanism.

The Effect of Compositional Gradient in Field Development

The existence of fluid’s compositional gradient in a reservoir drives convective flow which brings significant impacts to the operations, e.g., in formulation of injected fluid for well stimulation and enhanced oil Recovery (EOR). However, fluid compositional gradient is not always included in modeling reservoir performance due to PVT sampling limitation and simulation constraint. This work aims to show the significance of compositional convection in oil/gas reservoir and provides our experiences in dealing with this issue in Indonesian’s fields. PHE ONWJ as one of the most prolific producers of oil and gas in Indonesia currently operates an offshore block that has been producing for almost 40 years. Operating in a relatively mature well, PHE ONWJ often encounters significant fluid property change namely oil viscosity and specific gravity that changes overtime as depletion process occur. Data from X field, operated by PHE ONWJ, shows that compositional convection impacts workover and tertiary operations, by deviating from simulation results. We present the evidence of compositional convection using mechanistic models. We firstly adopt field data for setting the initial composition stratification. The stratification is identified through DST or fluid sampling. We secondly perform similarity simulation to analyze the effect of compositional gradient towards oil production. Similarity simulation is performed in the simplified domain for providing generalized solution. This solution is then scaled for the real domain. Finally, we show our approach to encounter the problems. Based on the similarity study inspired by the case of X Field, it shows that the compositional stratification affects geochemistry and near-wellbore flow behavior. The compositional convection develops multiple fluid properties at different depth, which create cross flow among layers. It also causes scale deposition in near wellbore which reduces the permeability and alters rock-fluid interactions, such as wettability and relative permeability. The alteration of near-wellbore geochemistry creates severe flow assurance issues in the wellbore. The mixing of multiple fluids from different layers cause paraffin and scale deposition. In some fields, the mixing triggers severe corrosions which could impact on wellbore integrity. The compositional stratification forces us to develop multiple treatments for different layers in single wellbore. Since the fluid’s properties are different for each layer, the compatibility between injected fluid and reservoir fluids varies.

Mitigating Scale Deposition by Optimization of Completion Valves Geometry

The harsh conditions presented in Brazilian presalt, summed up with the complexity of its reservoir, generate a series of challenges to improve reservoir recovery. Routinely, we have used intelligent completion systems to address the major part of the challenges; however, with the new production rates new problems have arrived and the usual ones have turned more aggressive, generating risks even to the intelligent completion systems. Inorganic scale is a critical challenge in presalt reservoirs production. Future plans for presalt production include more robust flow conditions and the use of an all-electrical completion system. Higher flow rates are likely to increase the risk of scale deposition and an optimum design is required. To address the new challenges arising from the new perspective of exploration in the presalt fields, we developed the presented workflow to mitigate the scale deposition on completion valves. The method enables the optimization of choke geometry to reduce scale deposition on inflow control valves. The proposed workflow generates a criticalness parameter for geometry classification according to a scenario of mechanical failure (due to sleeve incapacity to move) or deviation of production design point. A computational fluid dynamics (CFD) simulation was developed and benchmarked by experimental data, thus CFD results for different scenarios and various choke geometries were used to build a risk analysis matrix, which allows the definition of the optimal choke design to mitigate scale on ICVs. The extracted criticalness parameter may be used as an evaluator to estimate the time to valve stuck due to scale deposition in a commercial 1D transient flow simulator, optimizing then valve cycling time.

Scale Buildup Detection and Characterization in Production Wells by Deep Learning Methods

This study developed an analytical tool for the detection and characterization of scale buildup from well data using deep learning methods. The developed method allows for a sensitive detection of the initiation of scaling as well as an accurate prediction of the magnitude of existing scale buildup. Scale deposition causes tubing ID decreases and therefore results in production declines, so a sensitive approach to detect the scale deposition is valuable to reduce the damage and losses due to this problem. The underlying deep learning methods are both single- and multioutput, deep neural networks that consist of a combination of convolutional, long short-term memory (LSTM) and fully connected layers. We trained the networks on more than 30 sets of well data, with the objective of predicting the presence and the magnitude of scale. We started with cases of full scale deposition over the whole wellbore depth, and then extended our study to partial depth scale deposition. We built up a point-wise neural network model combining two blocks, which each contain several fully-connected layers followed by an LSTM layer specifically focusing on relatively smaller or larger tubing ID changes, corresponding to more or less scale deposition. To characterize the segmented scale deposition, we transformed to a three-dimensional problem, which can be solved by extracting the tubing ID changes and the scale deposition segment length. The multioutput model was able to predict the tubing ID and volume changes at the same time, using a combination of convolutional and LSTM layers with residual network blocks and updated using a loss function that we defined. Tubing ID changes were extracted accurately with metric R-square more than 90%, while the length of the scale deposit could be classified into two classes (high scaling or low scaling) with good accuracy. Though existing physical and chemical methods can be used to analyze scale deposition, the methods are often applied after considerable production decrease has already occurred. By using deep learning algorithms, our study came up with a new way to predict the scaling problem in advance with high sensitivity.

Flow Assurance in Buzios Field: Key Challenges and Implemented Solutions

This article's goal is to present some of the main flow assurance challenges faced by PETROBRAS in the Buzios oil field, from its early design stages to full operation, up to this day. These challenges include: hydrate formation in WAG (Water Alternating Gas) operations; reliability of the chemical injection system to prevent scale deposition; increasing GLR (Gas Liquid Ratio) management and operations with extremely high flowrates. Flow assurance experience amassed in Buzios and in other pre-salt oil fields, regarding all these presented issues, is particularly relevant for the development of future projects with similar characteristics, such as high liquid flow rate, high CO2 content and high scaling potential.