With maturing oil fields there is an increasing focus on improving the oil recovery factor and pushing the envelope toward a 70% target. This target is indeed very challenging and depends on a number of factors including enhanced oil recovery (EOR) methods, reservoir heterogeneities, displacement efficiency, and reservoir sweep. Other factors also play a role including vertical sweep due to flow behind the casing, well integrity issues, presence of conductive faults, or fractures. Proper surveillance performed to evaluate the injectant plume front, reservoir conformance, well connectivity, assessment of the integrity of wells, and other factors can be crucial for the success of the project and its future development.
The paper discusses special downhole logging techniques including a set of conventional multiphase sensors alongside high precision temperature (HPT) and high-definition spectral noise logging (SNL-HD). It was run to provide complete assessment of the injection – production distribution and any associated well integrity issues that might impair the lateral sweep of injectants into the target layer. This will be done for an injector and producer pair near the wellbore area. The operation was carried out with a tool string that contained no mechanical parts and was not affected by downhole fluid properties. It was conducted under flowing and shut-in conditions to identify flow zones and check fracture signatures. It also provided multiphase fluid velocity profiles.
The results of the survey allowed for in-depth assessment of borehole and behind casing flow, confirming lateral continuity, and provided an assessment of production-injection outside the pay zone. Results will allow for better well planning and anticipation of possible loss of well integrity that might impair production in the future. Combining the behind casing flow assessment with borehole multiphase flow distribution can be used for production optimization by sealing unwanted water contributing zones.
Reservoir fluid properties play a crucial role in the upstream field development cycle. Petroleum engineers extensively utilize Pressure-Volume-Temperature (PVT) studies in applications such as calculations of pipelines’ pressure drop, and assessment of Enhanced Oil Recovery (EOR) strategies. These studies are generated from a series of lab experiments conducted on reservoir fluid samples in high pressure-high temperature (HPHT) lab environments, and commonly matched using Equation of State (EOS) software.
Feeding and characterizing the composition of a reservoir fluid in a PVT software play a central role towards understanding its behavior. These steps are heavily affected by the last carbon number measured and the lumping scheme used in the simulator. This paper investigates the application of splitting the plus fraction, and utilizing Saturates, Asphaltenes, Resins and Aromatics (SARA) analysis in enhancing viscosity prediction at atmospheric conditions.
In this study, three oil samples from fields with suspected flow assurance issues were selected. A fingerprint study was first conducted on all samples to ensure that they are representative of the original reservoir fluid, and free of any drilling fluid contaminants. The methodology used in this study is based on conducting compositional analysis and viscosity test on the selected samples. Furthermore, SARA analysis was conducted to enhance the characterization of reservoir fluid, and confirm asphaltene presence. Lastly, splitting technique and SARA-based lumping scheme were used to predict viscosity values at atmospheric pressure and were compared to experimental data.
The results of this work demonstrated the effectiveness of SARA-based lumping scheme on atmospheric viscosity prediction, which captured the plus fraction concentrated in the dead oil without compromising the computational time. Furthermore, the EOS software used studied the sensitivity of the simulation results to different compositions.
Calcium sulfate scale precipitation is a challenge especially during stimulation treatments. The main objective of this study is to mitigate calcium sulfate precipitation during fracturing treatment. With high sulfate content in source/mixing water up to 2,000 parts per million (ppm) and excessive of total dissolved solids (TDS) formation water that can reach 60,000 ppm calcium.
An experimental study was conducted at the reservoir downhole temperature of 280°F to evaluate the formation water compatibility with source water wells used for fracturing fluids. The sulfate content varied in the fracturing fluids up to 2,000 ppm. This paper addresses: the scaling tendency of water-water interaction; the efficiency and minimum inhobitor concentration of three commercial calcium sulfate scale inhibitors; the stability of high sulfate fracturing fluids at 280°F (138°C) with scale inhibitors.
This study indicated: water-water compatibility tests reinforce the mineral risk assessments findings for calcium sulfate scales, scale inhibitors were effective to prevent scale deposition when added at 1.5 gpt to the source water. The high pH-fracturing gelled fluids must be prepared using relatively low sulfate water (SO42- ≤ 500 ppm). The scale inhibitors, when added to the high pH-fracturing, gelled fluids at minimum inhibit concertation will not negatively affect the polymer gel rheology and adhesion.
The study set guidelines to prevent calcium sulfate scales issues during fracturing jobs with incompatible source and extreme salinities formation water. The lesson learned exhibits an effective practice to maximize treatment efficiency and minimize formation damage that could be induced during fracturing.
Several aged oil wells in offshore oil field are drilled in a conventional method. These wells are subjected to Casing-Casing Annulus (CCA) problems that might appear during the production operation and/or the shutdown phases. A continuous monitoring is performed to avoid issues related to well integrity and safety. The expected source of Casing-Casing Annulus (CCA) problem is mainly due to poor primarily cementing placement into the outer-casing strings especially across shallow aquifers formations. Due to long shutdown period on subject wells, these wells are encountered with high rate of CCA phenomena among other wells. An immediate mitigation action is required to resolve the issues by applying rig workover operation which is considered highly cost approach with low success rate. The rig workover operation results might lead to suspension or abandonment of these wells. The impact will affect the production target and the oil recovery around the area.
A new methodology approach was selected using chemical sealant recipes as a rigless operation to repair CCA problem with cost-effective and safe manner for first time in offshore filed. Based on the wellhead and annuli survey, the bleed down and build up tests were conducted and followed by close monitoring on suspected wells, which revealed sustained casing pressures and fluid return at the surface. Several fluid samples were collected and analyzed in the lab. Based on the findings, the procedures and the proper design were conducted to inject the chemical sealant into connected cement channels behind casing strings. Curing time and injection rate with required volumes of chemicals were considered based on the pressure responses and chemical performance.
The results from the rigless operation job utilizing the new approach showed wide-ranging success rates based on well by well cases and conditions such as 1) Age of the well, 2) Sustained pressure observed at the surface, 3) Injectivity rates, 4) Chemical additives volume and 5) Downhole conditions (pressure / temperature).
The new technique added a great value on restoring the well integrity and saving the rig operation cost. In addition, the approach contributed to achieve maximum sustainable production target through ensuring the well operability and reducing the production down time. Challenges, methodology, work schedule, risk assessment, lessons learned and findings have been covered in this paper.
Lara Orozco, Ricardo A. (The University of Texas at Austin) | Abeykoon, Gayan A. (The University of Texas at Austin) | Wang, Mingyuan (The University of Texas at Austin) | Argüelles Vivas, Francisco J. (The University of Texas at Austin) | Okuno, Ryosuke (The University of Texas at Austin) | Lake, Larry W. (The University of Texas at Austin) | Ayirala, Subhash C. (Saudi Aramco) | AlSofi, Abdulkareem M. (Saudi Aramco)
Reservoir wettability plays an important role in waterflooding especially in fractured carbonate reservoirs since oil recovery from the rock matrix is inefficient because of their mixed wettability. This paper presents the first investigation of amino acids as wettability modifiers that increase waterflooding oil recovery in carbonate reservoirs.
All experiments used a heavy-oil sample taken from a carbonate reservoir. Two amino acids were tested, glycine and β-alanine. Contact angle experiments with oil-aged calcite were performed at room temperature with deionized water, and then at 368 K with three saline solutions: 243,571-mg/L salinity formation brine (FB), 68,975-mg/L salinity injection brine 1 (IB1), and 6,898-mg/L salinity injection brine 2 (IB2). IB2 was made by dilution of IB1.
The contact angle experiment with 5-wt% glycine solution in FB (FB-Gly5) resulted in an average contact angle of 50°, in comparison to 130° with FB, at 368 K. Some of the oil droplets were completely detached from the calcite surface within a few days. In contrast, the β-alanine solutions were not effective in wettability alteration of oil-aged calcite with the brines tested at 368 K.
Glycine was further studied in spontaneous and forced imbibition experiments with oil-aged Indiana limestone cores at 368 K using IB2 and three solutions of 5 wt% glycine in FB, IB1, and IB2 (FB-Gly5, IB1-Gly5, and IB2-Gly5). The oil recovery factors from the imbibition experiments gave the Amott index to water as follows: 0.65 for FB-Gly5, 0.59 for IB1-Gly5, 0.61 for IB2-Gly5, and 0.33 for IB2. This indicates a clear, positive impact of glycine on wettability alteration of the Indiana limestone cores tested.
Two possible mechanisms were explained for glycine to enhance the spontaneous imbibition in oil-wet carbonate rocks. One mechanism is that the glycine solution weakens the interaction between polar oil components and positively-charged rock surfaces when the solution pH is between glycine's isoelectric point (pI) and the surface's point of zero charge (pzc). The other mechanism is that the addition of glycine tends to decrease the solution pH slightly, which in turn changes the carbonate wettability in brines to a less oil-wet state.
The amino acids tested in this research are non-toxic and commercially available at relatively low cost. The results suggest a new method of enhancing waterflooding, for which the novel mechanism of wettability alteration involves the interplay between amino acid pI, solution's pH, and rock's pzc.
When a restriction or nonconformity presents itself in a well, quickly and reliably diagnosing the nature of the anomaly can save diagnostic runs and help prevent similar cases elsewhere, reducing nonproductive time and operating costs. Downhole X-ray diagnostics provide this understanding quickly and reliably under diverse well conditions that limit the effectiveness of other downhole diagnostic techniques. X-ray diagnostics produce real-time, quantitative two-dimensional images and three-dimensional reconstructions of downhole objects and obstructions with high precision. We demonstrate this with a case study in which X-ray diagnostics accurately identified and quantitatively characterized an obstruction due to liner deformation.
Offshore field started on operation to produce crude oil with 27 API° as sweet crude and sour crude with 32 API° since 1960. Large number of wells in offshore field revealed undesirable phenomena related to well integrity issues as potentially sustained pressure on several casing strings. Well integrity management emphasis on preventing well problems related to well safety and integrity such as casing leak, Sustained Casing Pressure (SCP), downhole safety valve (DHSV) failures. The direct impact from integrity management added great value in terms of decreasing in operating down time, improvement in well control and safety aspects, and reducing unplanned repair intervention. In addition, the loss of well integrity can cause major accidents with a severe risk to the personnel, asset and environment.
The paper aims to illustrate a methodology results on applying effective well integrity monitoring techniques. A focus was made to improve monitoring well integrity through reviewing wellhead surface parameters, annulus sections pressure and downhole condition. In addition, the subject wells should be kept under close monitoring at a safe operable with an integral condition. Non-integral wells are common in aged wells, which are becoming a challenging issue to restore its integrity and operability especially for such aged completion. As a part of well integrity review, the concerns had been identified, investigated, and subsequently mitigations actions are recommended to restore the well integrity. Currently, it is confirmed that 25 oil producers with casing leak problems, which resulted to be converted from conventional completion to a slim hole with limited future accessblity. Based on lab reusltes and logging interpretations, it is indicated that the root cause of casing leaks is due to corrosive water flow from shallow aquifer formation. Therefore, an immediate remedial action is required to improve well construction.
A successful worked over well with integrity issue as a casing leak was repaired by cement squeeze into across the corroded casing interval, which enhanced well integrity and restore well productivity. The resulted showed that tubing leaks encountered with well integrity due to sustained casing pressure. Therefore, the pressure on production casing can cause severe failure with catastrophic damage. The results also illustrated that a water flow through poor cement is a major cause of sustained casing pressure in the outer casing strings. The cause of pressure on production casing is generally easier to diagnose than that pressure on one of the outer casing strings. Challenges, methodology, work schedule, risk assessment, lesson learned and findings are included in this paper. The effective well integrity management resulted on great deal of benefits, which are related to securing wells, well operability, cost saving, and sustained maximum production target.
Zhu, Jianjun (University of Tulsa) | Zhu, Haiwen (University of Tulsa) | Cao, Guangqiang (PetroChina Company Ltd.) | Banjar, Hattan (Saudi Aramco) | Peng, Jianlin (University of Tulsa) | Zhao, Qingqi (University of Tulsa) | Zhang, Hong-Quan (University of Tulsa)
As the second most widely used artificial lift method in petroleum industry, ESPs help maintain or increase flow rates by converting kinetic energy to hydraulic pressure. During the entire life of an oilfield, water is invariably produced with crude oil. As the field ages, the water cut in production increases. Due to high shear force inside rotating ESPs, the oil-water emulsions may form, which can be stabilized by natural surfactants or fine solids existing in the crude oil. The formation of emulsions during oil production create high viscous mixture, resulting in costly problems and flow assurance issues, such as pressure drop increase and production rate lost. This paper, for the first time, proposes a new mechanistic model for predicting oil-water emulsion rheology and its effect on the boosting pressure in ESPs. The model is validated with experimental measurements with an acceptable accuracy.
The new mechanistic model starts from Euler equations for centrifugal pump, and introduces a conceptual best-match flowrate
The mechanistic model-predicted ESP water performance curves are found to match the catalog curves perfectly. With high-viscosity fluid flow, the model predictions of ESP boosting pressure agree well with the experimental data. For most calculation results within medium to high flow rates, the prediction error is less than 15%. With oil-water two-phase flow, the proposed rheology model predicts the effective viscosities of emulsions match testing results with 10% prediction error. The inversion points, at which the continuous phase changes from oil to water as water cut increases, are also predicted. The predictions of ESP boosting pressure under oil-water emulsion flow by coupling the mechanistic model and emulsion rheology model are comparable with experimental results.
Fluid flow invasion is governed by the characteristics of the pore structure in the porous media. The flow is restricted due to the increase of net stresses near borehole after drilling. Understanding the fluid flow at the pore scale becomes an important aspect of successful operations such as matrix acidizing or fluid formation treatment. The aim of this work is to demonstrate the ability of using Lattice-Boltzmann formulations to solve the complex fluid flow system in the porous medium as compared to a Darcy type of flow analysis using geomechanical approaches. The simulations were performed at the same physical scale. The reduction of pore size at the vicinity of the borehole is approximated using different geometrical domains to mimic the fluid invasion process as a result of change in net stresses.
Micromodels are commonly utilized to investigate the fundamentals of multiphase displacements and oil mobilization. Definitely, the utility of micromodels has been well demonstrated in the literature. Yet, while the generic workflows are mutual, there is no standard protocol. Therefore, the primary objective of this work was to develop reliable protocols for micromodel experimentations. These protocols are developed within the context of investigating flow-rate effects on oil trapping and recovery, which represents a supplementary objective.
The presented experimental work utilized a high pressure and high temperature setup. A metalloid pattern with a pore-volume of 0.08 mL constitutes the porous-media micromodel. The model is positioned vertically, which permits investigation of gravity effects. Displacement experiments were performed to establish the image processing workflow. Those experiments were performed at different injection rates for fixed volumes starting from 10 mL up to 50 mL. All experiments were replicated to assess the associated uncertainties. Initial conditions were established via drainage of connate brine by dead crude oil followed by imbibition of injection brine.
The performed experiments established a preferred workflow for image processing that includes in order: thresholding, despeckling, and binary conversion. Thresholding limits were found to be dependent on the camera including its position and focal length. The final binary images can be used for oil recovery estimation based on areal analyses. High rate experiments demonstrated better repeatability. Prolonged injection helped reduce variations in recovery estimates between replicates. At the investigated macroscopic scale and in light of associated uncertainties, recovery was found to be negligibly dependent on injection rate up to a critical flow-rate of around 1 mL/min above which recovery increases with higher injection rates. A trend that is consistent with capillary desaturation.
This paper demonstrates the procedure to establish a micromodel image processing protocol. It also illustrates the possible uncertainties associated with recovery estimates obtained from such images. Finally, key observations and recommendations with respect to the significance of high throughput and replications were uncovered.