Synthetic Oil-based Mud Research Articles

Effect of temperature on transport index of fish oil-based drilling mud in high pressure high temperature well: a hybrid model approach

Diesel Oil-based drilling mud used in the oil and gas industry causes severe environmental and public health issues due to its high toxicity, especially in high-pressure, high-temperature (HPHT) wells. Therefore, easily biodegradable synthetic oil-based mud with high drilling performance is essential. Fish oil is a bio-oil known for its non-toxicity, high lubricity, thermal stability, and biodegradability. Effective hole cleaning is crucial for drilling performance and is ensured by the rheological properties of drilling mud. While rheological parameter prediction can be performed using an artificial neural network (ANN) based model, such models often fail to provide accurate predictions for unseen data. In contrast, empirical models are more robust and facilitate generalization. This study aims at assessment of the suitability of invert emulsion fish oil-based drilling mud (IEFOBDM) in HPHT wells through evaluation of hole cleaning performance (HCP) using a hybrid approach that combines an ANN with nonlinear regression (NLR) for temperatures ranging from 40 °C to 80 °C.Firstly, an ANN model was developed considering mud weight, temperature, and shear rate. Secondly, the NLR model was used in the prediction of rheological parameters, namely, Yield point (YP) and Plastic viscosity (PV), based on the predicted shear stress from the ANN model. Finally, the performance metrics of the ANN-NLR rheological model were evaluated using the root mean square error (RMSE) and correlation coefficient (R2) and comparison made with the Single ANN rheological model. The results showed the outperformance of ANN-NLR model over the ANN model for rheological parameter prediction, with R2 values of (0.99) for YP and (1) for PV. The predicted PV and YP values were then used for evaluation of transport index (TI) for HCP analysis. The effect of temperature on TI analysis showed this with increase in temperature, TI also increased, indicating the proposed mud providing good HCP under HPHT conditions.

Machine-Learning Approach PredictsGel Strength of Drilling Fluid While Drilling

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 35433, “Novel Machine-Learning Approach for Predicting the Gel Strength of the Drilling Fluid While Drilling,” by Ahmed Gowida, SPE, and Salaheldin Elkatatny, SPE, King Fahd University of Petroleum and Minerals. The paper has not been peer reviewed. Copyright 2024 Offshore Technology Conference. _ Accurately estimating gel strength is paramount for optimizing drilling operations and preventing cuttings from settling at the wellbore’s bottom. Traditional methods rely on rotational viscometers, which are time-intensive, equipment-dependent, and lack real-time monitoring capabilities. This study underscores the feasibility of leveraging machine learning (ML) as a practical tool for predicting drilling-fluid gel strength, offering real-time monitoring and precise predictions to enhance drilling efficiency, safety, and automation initiatives. Background The gel strength of drilling fluid is assessed using a viscometer, focusing on the 3-rev/min reading obtained after agitating the fluid at 600 rev/min to disrupt any gel formation. Initially, the measurement is taken when the mud reaches a static state for 10 seconds. Subsequent readings are conducted at 10- and 30-minute intervals. The rationale behind the 30-minute reading lies in its ability to indicate whether the mud forms a substantial gel during prolonged static periods, such as when tripping out a bottomhole assembly. Elevated gel strength may result in increased pump pressure required to restore circulation after extended static conditions. Additionally, a consistent upward trend in the 30-minute gel strength suggests the accumulation of ultrafine solids. Consequently, appropriate measures such as chemical treatments or dilution with fresh base fluid are necessary to address this issue. The frequency of measuring various fluid properties is tailored to their respective effects on well-control and drilling operations. These frequent evaluations allow for timely adjustments and monitoring of rheological measurements, offering valuable insights into rock sensitivity and the performance of mud activity and stability after exposure to drilled formations. On the other hand, a complete mud test (including all mud rheological properties) is performed twice a day because it consumes considerable time. It has been observed that mud rheological properties exhibit a significant correlation with two fundamental mud properties: mud weight and Marsh funnel (MF) viscosity. To the best of the authors’ knowledge, a dearth of research exists in the literature aimed at predicting the gel strength of drilling fluid using ML techniques. Consequently, this research endeavor introduces a novel ML model designed specifically for forecasting the gel strength of synthetic oil-based mud systems. Such predictive models are poised to enhance drilling performance by optimizing mud functions. Leveraging MF and mud-density measurements, the developed models aim to forecast the rheological properties of drilling fluid, thereby facilitating improved monitoring of mud functionality during drilling operations at the rig site.

Technology Focus: Drilling and Completion Fluids (November 2024)

This year’s primary selections for the Drilling and Completion Fluids Technology Focus reflect now-well-established industrywide emphases on machine learning (ML), automation, and the achievement of successful drilling of CO2 storage wells. Enhanced methods of modeling and monitoring allow time and cost savings while surpassing safety goals and furthering efforts to optimize CO2 storage. Paper OTC 35433 discusses a study centered on accurate gel-strength estimation. The authors leverage ML techniques, particularly the use of artificial neural networks, to develop predictive models for forecasting the gel strength of synthetic oil-based mud systems at both 10-second and 10-minute intervals, surpassing the precision and speed of techniques based on traditional rotational viscometers. In a similar vein, paper SPE 216322 seeks to bypass traditional manual methods of monitoring drilling fluids, its authors describing a novel online system that measures 10 key parameters continuously. They write that the system has been field-trialed across 200 wells with results that highlight the system’s reliability, with continuous operation for over 125 days. Finally, paper SPE 217711 involves evaluating the effects of an influx of CO2 into drilling fluids, a key task in the drilling of CO2 storage wells. Concentrating on oil-based drilling fluid, the presented study describes the development and integration of models for properties of drilling-fluid/CO2 mixtures into an existing software suite. Recommended-reading papers include an investigation of the use of microwave power in recovering oil from contaminated drill cuttings, reduction of the carbon footprint of drilling fluids, and sedimentation behavior of particles in fibrous sweep fluids. As always, the long-sighted ambition of such research, and the skill applied in its pursuit, reflects the commitment to excellence embodied by the authors of technical papers presented at SPE conferences. Recommended additional reading at OnePetro: www.onepetro.org. SPE 217140 Microwave-Assisted Technique for Oil Recovery From Oily Sludge Shale Drilled Cuttings by A. Agi, Universiti Malaysia Pahang, et al. OTC 34667 Successful Decarbonization of Drilling Fluids by Using Highly Efficient Technology and Reduced Chemical Usage, Logistics, and Casing Sections by Gerardo Jardinez, Pemex, et al. SPE 218631 Application of Machine-Learning Method for Modeling Settling Behavior of a Spherical Particle in Fibrous Drilling Fluids by R.M. Elgaddafi, Australian University, et al.

A novel star polymer for regulating fluid loss in oil-based mud under high temperature conditions

Oil-Based Mud (OBM) is a highly effective drilling fluid system for challenging wellbore conditions such as water-sensitive and high-temperature drilling operations. To minimize filtration loss and achieve thin filter cake, fluid loss control additives are essential. This study introduces a star polymer as an alternative to traditional additives like gilsonite or linear polymer. The star polymer was synthesized using Reversible Addition Fragmentation Chain Transfer polymerization (RAFT) with hydrophilic and lipophilic monomers and crosslinkers. Mud properties such as rheology, fluid loss, mud cake thickness, and emulsion stability were evaluated for OBM and compared with commercially available fluid loss control additives at simulated downhole pressure and temperatures. Spectroscopy and thermogravimetric analysis were used to determine the chemical architecture and thermal stability of the star polymer. The results showed that the star polymer demonstrated thermal stability up to 225 °C, resulting in a small amount of fluid loss volume and ultra-thin filter cake for OBM systems with mud weight at 10.5 ppg and 13.4 ppg. Furthermore, the star polymer improved emulsion stability without significantly affecting plastic viscosity (PV), unlike commercially available fluid loss control additives. The results were consistent for both diesel and synthetic oil-based mud systems.

Empirical Correlations for Predicting Flow Rates Using Distributed Acoustic Sensor Measurements, Validated with Wellbore and Flow Loop Data Sets

Summary Distributed acoustic sensing (DAS) is an emerging surveillance technology that is becoming increasingly popular in the oil and gas industry for real-time flow monitoring. However, there are limited studies that rigorously quantify flow rates using DAS. This work expands the existing literature by presenting a detailed workflow for accurately estimating fluid flow rates from DAS data using time- and frequency-domain signal processing. Three simple empirical correlation functions (linear, exponential, and cubic) are developed and tested to predict flow rates from DAS. The proposed correlations are demonstrated for flow rates ranging from 50 to 300 gallons per minute (GPM) in a vertical 5,163-ft-deep wellbore and from 12 to 36 GPM in a horizontal surface flow loop. Tests were performed using a single-phase flow of water as well as using synthetic oil-based drilling mud. Time-domain DAS processing using root-mean-square (RMS) value and frequency-domain processing using frequency band energy (FBE) is evaluated, followed by a statistical approach to minimize the influence of outliers. The RMS and FBE approaches are individually compared for flow prediction, and the performance of the correlations is rigorously evaluated on a blind data set that was not originally used for developing the correlations. For both the wellbore and flow loop data sets, a coefficient of determination (or R2) greater than 0.95 with an average flow rate prediction error of less than 10% was achieved for the best-performing correlation for the blind test data. The analysis procedure and workflow presented in this study can be adopted and extended to different operating conditions for quantitative flow rate prediction using DAS.

Data-Driven Framework for Real-time Rheological Properties Prediction of Flat Rheology Synthetic Oil-Based Drilling Fluids.

Appropriate mud properties enhance drilling efficiency and decision quality to avoid incidents. The detailed mud properties are mainly measured in laboratories and are usually measured twice a day in the field and take a long time. This prevents real-time mud performance optimization and adversely affects proactive actions. As a result, it is critical to evaluate mud properties while drilling to capture mud flow dynamics. Unlike other mud properties, mud density (MD) and Marsh funnel viscosity (MFV) are frequently evaluated every 15-20 min in the field. The goal of this study is to predict the rheological properties of flat rheology synthetic oil-based mud (SOBM) in real time using machine learning (ML) techniques such as random forest (RF) and decision tree (DT). A proposed approach is followed to first predict the viscometer readings at 300 and 600 RPM (R 600 and R 300) and then estimate the other mud properties using the existing equations in the literature. A set of data contained MD, MFV, and viscometer readings (R 300 and R 600) for different samples from the same mud type. The mud samples were collected after going through a shale shaker. MD and MFV are measured by a mud balance and a Marsh funnel, respectively, while rheology is evaluated using a viscometer. The data were randomly split into training, testing, and validation data sets. The ML models' performance was evaluated through average absolute percentage error (AAPE) and correlation coefficient (R). The proposed models predicted the viscometer readings as a middle stage with a low AAPE that did not exceed 4.5% for both models. The suggested models forecasted the rheological properties with a good degree of accuracy, with an AAPE being less than 7% for most of the parameters. The proposed models can save costs and time since there is no need to include additional tools in the rig location. Furthermore, these models will significantly aid in avoiding serious problems and achieving better rig hydraulics and hole cleaning, which in turn will technically and economically enhance drilling operations.

Machine Learning Model for Monitoring Rheological Properties of Synthetic Oil-Based Mud.

The drilling fluid rheology is a critical parameter during the oil and gas drilling operation to achieve optimum drilling performance without nonproductive time or extra remedial operation cost. The close monitoring for rheological properties will help the drilling fluid crew to take quick actions to maintain the designed profiles for the drilling fluid rheology, especially when it comes to the flat rheology drilling fluid system, which is a new generation for harsh and specific drilling conditions that require flat profiles for the mud rheology regarding the temperature condition changes. The current study introduces a machine learning application toward predicting the rheology of synthetic oil-based mud (flat rheology type) for the full automation system of monitoring the mud rheological properties. Four models are developed, for the first time, to determine the rheological characteristics of flat rheology synthetic oil-based system using artificial neural networks. The developed models are capable of predicting the plastic and apparent viscosities, yield point, and flow behavior index from only the mud density and Marsh funnel as model inputs. The proposed models were trained and optimized from a real field dataset (369 measurements) with further testing the models using an unseen dataset of 153 data points. The predicted rheological properties achieved a high degree of accuracy versus the actual measurements and showed a coefficient of correlation range from 0.91 to 0.97 with an average absolute percentage error of less than 9.66% during the training and testing phases. Besides, machine learning-based correlations are proposed for estimating the rheological properties on the rig site without running the machine learning system for easy field applications.

In-Situ Visualization and Characterization of Filter-Cake Deposition Using Time-Lapse Micro-CT Imaging

This work establishes and verifies a laboratory method for accurate, noninvasive, and nondestructive in-situ measurement of filter-cake, or mudcake, properties using high-resolution X-ray microcomputed tomography (micro-CT). Accurate in-situ characterization of mudcake properties is of vital importance for understanding mudcake deposition during mud-filtrate invasion and, more broadly, the deposition of filter cake during industrial filtration processes. The developed laboratory method involves the injection of pressurized drilling mud into a borehole located at the center of a cylindrical rock core sample. Radial mud-filtrate invasion is induced by maintaining the outside of the core sample at a lower pressure. Mudcake is deposited on the borehole wall while mud filtrate flows into the surrounding pore space of the core sample. Simultaneously, the core sample is continuously scanned using high-resolution X-ray micro-CT, allowing for three-dimensional (3D) in-situ visualization and characterization of the deposited mudcake. Analysis of experimental results is aided by a new set of filtration equations that are generalized for use with either water-based mud or invert emulsion drilling fluids, such as oil- or synthetic oil-based mud. Each experiment produces a time-series data set consisting of injected mud volume and the corresponding in-situ average mudcake thickness, porosity, and permeability. Results are presented for experiments involving injection of water- and synthetic oil-based drilling mud. We observe that experimental measurements agree well with modeled results when mudcake is thin compared to the size of the borehole—a condition that would be satisfied under most normal field conditions. Initial results also suggest that the developed method may be capable of providing accurate in-situ 3D measurements of local filter-cake properties during compressible cake filtration, which has significant implications for a wide range of industrial applications.

Realistic Simulation of Multiphase Kick Tolerance Model Promotes Safer Well Control Operations: Case Study

Nowadays, deep-water drilling is of great importance for the development of oil and gas production. It is necessary to determine the maximum pressure that the formation can withstand during well control operation. This value can be calculated using several variables, including kick tolerance. The purpose of this study is to analyze a real well control event using dynamic well control modeling software that calculates the kick tolerance based on the single-phase and multiphase dispersed kick (gas) model. The initial results show that the type of drilling fluid plays an important role in the calculation of the kick tolerance. The calculated kick tolerance using a single-phase model indicates an allowable kick volume of 56 barrels (bbls), but in reality, we had a dispersed gas kick in a synthetic oil-based mud (SOBM) drilling fluid, which requires special kick tolerance calculations based on a multiphase dynamic model. After reviewing the results of the multiphase kick tolerance simulation, it was found that the maximum gas kick volume is more than twice that of using a single-phase model in an oil-based mud drilling fluid, allowing safe well control operations and reducing the possibility of accidents.

Identifying Formation Creep: Ultrasonic Bond Logging Field Examples

Summary As part of plug and abandonment (P&A) operations, several acceptance criteria need to be considered by operators to qualify barrier elements. In casing annuli, highly bonded material is occasionally found far above the theoretical top of cement. This paper aims to describe how the highly bonded material can be identified using a combination of ultrasonic logging data, validated with measurements in laboratory experiments using reference cells and how this, in combination with data from the well construction records, can contribute to lowering the costly toll of P&A operations. Ultrasonic and sonic log data were acquired in several wells to assess the bond quality behind multiple casing sizes in an abandonment campaign. Data obtained from pulse-echo and flexural sensors were interactively analyzed with a crossplotting technique to distinguish gas, liquid, barite, cement, and formation in the annular space. Within the methodology used, historical data on each well were considered as an integral part of the analysis. During the original well construction, either water-based mud (WBM) or synthetic oil-based mud (OBM) was used for drilling and cementing operations, and some formation intervals consistently showed high bonding signatures under specific conditions, giving clear evidence of formation creep. Log data from multiple wells confirm that formation behavior is influenced by the type of mud used during well construction. The log data provided information of annulus material with a detailed map of the axial and azimuthal variations of the annulus contents. In some cases, log response showed a clear indication of formation creep, evidenced by a high bond quality around the production casing where cement cannot be present. Based on observations from multiple fields in the Norwegian continental shelf, a crossplot workflow has been designed to distinguish formation from cement as the potential barrier element. NORSOK Standard D-010 (2013) has initial verification acceptance criteria both for annulus cement and creeping formation as a well barrier element, both involving bond logs; however, in the case of creeping formation, it is more stringent stating that “two independent logging measurements/tools shall be applied.” This paper aims to demonstrate how this can be done with confidence using ultrasonic and sonic log data, validated against reference barrier cells (Govil et al. 2020). Logging responses like those gathered during full-scale experiments of reference barrier cells with known defects were observed in multiple wells in the field. Understanding the phenomenon of formation creep and its associated casing bond signature could have a massive impact on P&A operations. With a successful qualification of formation as an annulus barrier, significant cost and time savings can be achieved.

Investigating the potential of Calophylluminophyllum plant base oil for oil and gas drilling mud operations

The environmental and cost advantage of non-edible plant oil for potential base oil in oil and gas drilling mud formulation is a drive for its use. The seed of Calophylluminophyllumthe plant oil was processed, pulverized, and oil extracted using chemical method. The extracted plant oil and commercial synthetic oil was used to formulate drilling mud and comparative analysis were made using the physicochemical properties of the oil samples, mud rheological properties under sixteen hours and 240 °F aging and non-aging effect for a 7 and 9 g viscosifier, and rheological models in describing the mud. The commercial synthetic oil and Calophylluminophyllum oil shows a flash point of 101 ± 0.1 and 164 ± 0.1; density of 108 and ; viscosity index of 192 and 163; acid value of NIL and 24.24; and oil yield of NIL and 71 % respectively. The rheological properties of Calophylluminophyllum oil-based mud were higher than the synthetic oil-based mud. It was also observed that the increase in temperature and viscosifer decreases and increases the rheological properties respectively of all mud samples. The synthetic and Calophylluminophyllum oil-based mud increased in the rheological properties after aging test. In the overall estimation of the root mean square error (RMSE) values, coefficient of determination R2 values, and the fitted plots analysis. The Herschel Bulkley and the Sisko model had a much better description in predicting the experimental data for the synthetic oil-based mud. The hyperbolic, Herschel Bulkley and Sisko model had good description for the experimental data of the Calophylluminophyllum oil-based mud.

The rheological behavior of a pseudo-oil-based mud formulated with Hura crepitans plant oil as base fluid

The need to prevent our environment from deterioration caused by toxic waste from drilling mud is a prime objective to the oil and gas industry. The exploration of non-edible plant oil for potential base oil in formulating drilling mud is progressing due to the environmentally friendly nature. This research work involves using a commercial synthetic oil from the oil industry and Hura crepitans oil. This oil samples were used as a base fluid in preparing the mud from which the rheological properties were analyzed. Chemical oil extraction method using soxhlet apparatus was used to extract the oil from H. crepitans seeds; it was then distilled to remove the solvent. The mud samples were formulated with 7 and 9 g concentrations of the viscosifier, and properties were measured at 113 and 158 °F. It was then aged for 16 h at 240 °F, and mud properties were measured before and after hot rolling for comparison. Different rheological models were used to describe the experimental data. The physical properties of the synthetic oil and H. crepitans oil reveal a flash point of 213.8 and 399.2 °F, fire point of 226.4 and 500 °F, viscosity index of 297 and 207, specific gravity/density of 805 and 907, respectively. The mud properties of the synthetic oil-based mud had a better emulsion stability, lower plastic viscosity, higher yield point values, and lower gel strength than the H. crepitans oil-based mud. The rheological properties of synthetic and H. crepitans oil-based mud increase and decrease, respectively, after hot rolling. The optimal concentration of viscosifier was 7 g to have maintained the API acceptable range for the rheological properties. Based on the R^{2} values, RMSE values, and the fitted plots, Herschel–Bulkley had a better description of the experimental data.

Offshore HP/HT Gas Well: Drilling and Well Testing

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 155320, ’Offshore Drilling and Well Testing of an HP/HT Gas Well: A Case Study,’ by Prerak H. Shah, SPE, Harsh T. Pandya, SPE, Harsh Sharma, and Arpit Saxena, SPE, Gujarat State Petroleum Corporation, prepared for the 2012 SPE Oil and Gas India Conference and Exhibition, Mumbai, 28-30 March. The paper has not been peer reviewed. With exploration in harsh environments and consequent high-pressure and high-temperature conditions, calculating reservoir properties has become complex and changes in pressure-transient response need to be understood and appreciated by taking appropriate measures. The challenges arising with drilling and testing of high-pressure/high-temperature (HP/HT) gas wells that produce hydrogen sulfide (H2S) and carbon dioxide (CO2) in the Krishna Godavari basin are discussed. Introduction In the exploration campaign in the Krishna Godavari basin off the east coast of India, four wells were drilled, discovering a very tight gas reservoir with an average pressure of 12,000 psi and an average re-corded temperature of 360°F and classified as an HP/HT reservoir, as shown in Fig. 1. This paper discusses the experience drilling four wells with a jackup rig in average water depth of 60 m. Well-A was the first well. Well-B dis-covered and flowed gas from stratigraphy below the section encountered in Well-A. Well-C encountered the same sands found in Well-A, and additional shallower sands not encountered in Well-A or Well-B were discovered. The reservoir section is overlain by shale. Well-A was drilled in six sections because it was the first exploratory well; the other three wells were drilled in five sections. All wells had sections of 36-, 26-, 17½-, 12¼-, and 8½-in. hole and Well-A had an additional 6-in. section. These sections were cased with 30-, 20-, 13⅜-, 9⅝-, and 7-in. liner casings, respectively, and Well-A included a 5-in. liner. The reservoir section expected in 8½-in. hole from seismic and log data was proved while drilling Well-A and was appraised in Well-B, Well-C, and Well-D. Well-A and Well-B were drilled to total depth with water-based mud (WBM). The 12¼-in. section of Well-C was drilled with WBM, while the 8½-in. section was drilled with synthetic-oil-based mud (SOBM). The shale sections and reservoir section in Well-D were drilled using SOBM. The mud program was designed on the basis of the pore-pressure-leakoff-test (LOT) vs. depth chart shown in Fig. 2.

Rock quality assessment using the effect of mud-filtrate invasion on conflicting borehole resistivity measurements

Unexpected borehole measurements are often inaccurately interpreted due to limited knowledge of the formation, particularly in tight-gas unconventional reservoirs. A novel method was applied to determine reservoir quality and the reliability of borehole array-induction resistivity measurements in a tight gas sandstone reservoir. Four exploration wells drilled with synthetic oil-based mud showed conflicting resistivity profiles. The discovery well showed a conductive invasion profile, but the appraisal wells showed resistive profiles. Simulation of oil-based mud-filtrate invasion was coupled with forward simulation and inversion of array-induction resistivity measurements to determine the difference in such resistivity profiles. Laboratory measurements on rock core and fluid samples were used to calibrate a log-based petrophysical model that was necessary to simulate the physics of fluid-flow mud-filtrate invasion. The dynamic process of invasion was simulated with a multicomponent formulation for the hydrocarbon phase and rock wettability alteration effects due to surfactants present in the mud. Simulated borehole-resistivity measurements were compared to field logs, and the rock properties were modified to secure a close agreement between simulated and field logs. The different invasion profiles corresponded to variable rock quality and mud composition. In the discovery well, good rock quality and thick surfactants in the mud caused a low mobility ratio between filtrate and native fluids, which created a water bank that moved ahead into the formation. This effect created a conductive annulus in the near-wellbore region. In turn, the deep invasion and high resistivity are due to excellent rock quality that is typical of a conventional sandstone reservoir. The shallower invasion and resistive profiles in the delineation wells suggest the tight gas sandstone reservoir we expected to find throughout the formation.

Multidiscipline Approach, Advanced LWD Boost Multistage Fracturing in Romania

Technology Update Since the start of production from the Lebada fields offshore Romania in 1987, operator Petrom tested various stimulation and completion measures to improve production from the fields’ low-permeability formations. However, by 2008, the company had not been able to achieve production of more than approximately 115 BOEPD per well. A new multidisciplinary approach to well design, combined with the implementation of advanced directional drilling, logging-while-drilling (LWD), and completion technologies, has now increased production per well to a peak of more than 1,000 BOEPD and to stabilized levels of up to 750 BOEPD. Petrom is the largest oil and gas producer in southeastern Europe. It was Romania’s national oil company until privatized in 2004, when it became a member of the OMV Group. Romania has been producing oil since 1856, mostly from onshore reservoirs. Petrom currently produces approximately 32,000 BOEPD from its five commercial offshore fields in the Black Sea, approximately 18% of the company’s annual 66 million BOE production in Romania (2009 figures). The Lebada Oil Fields Petrom’s Lebada Est (East) and Lebada Vest (West) fields are in block Histria XVIII in the Black Sea. Lebada Est was discovered in 1978 and represented Romania’s first offshore production when it came onstream in 1987. It produces oil from Upper Cretaceous carbonate shelf deposits—micritic, sandy and chalky limestones—overlain by overpressured Oligocene shales. Average porosity is 15% to 20% and average permeability is 0.8 md. Microfractures and intergranular porosity connect zones with good porosity in mainly calcareous reservoir forma-tions. Lebada Vest was discovered in 1985, with first production occurring in 1993. It is characterized by the same calcareous formations as Lebada Est in the top part and more clastic turbiditic fan deposits toward the bottom. A gas cap is often present. In 2008, Petrom reviewed technical proposals to increase production rates significantly, having achieved only very limited success until then with measures such as acid fracturing and hydraulic fracturing of older producers completed with cemented and perforated liners. It was concluded that high production would require long horizontal drain sections with good quality borehole to be drilled. Because the hydrocarbons lay within shelf deposits, horizontal continuation of reservoir properties could not be guaranteed. Thus, real-time petrophysical evaluation and well placement would be necessary. Synthetic oil-based mud (SOBM) would be beneficial to handle the Oligocene overpressured shale overburden, provide a better quality hole, and enable safe drilling, helping to ensure efficient, effective completions run along the reservoir section. However, this could limit the choice of formation evaluation logging tools. The low-permeability reservoir rock required hydraulic fracturing and fast, efficient, postdrilling reservoir characterization and natural open fracture detection to select the best locations for placing completion packers and ports.

Very Low Water Saturations Confirmed in Sandstones

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 113162, "Very Low Water Saturations Within the Sandstones of the Northern Barmer Basin, India," by T. O'Sullivan, SPE, Cairn India; R.J. Zittel, SPE, Cairn Energy; D. Beliveau, SPE, Cairn India; S. Wheaton, SPE, Tullow Oil; H.R. Warner Jr., SPE, and R. Woodhouse, SPE, Independent Consultants; and B. Ananthkrishnan, Cairn India, prepared for the 2008 Indian Oil and Gas Technical Conference and Exhibition, Mumbai, 4-6 March. The paper has not been peer reviewed. The Mangala, Bhagyam, and Aishwariya (MBA) fields were discovered in 2004 in the northern Barmer basin of Rajasthan, in northwestern India. The data acquired from field wells enabled a precise estimation of oil initially in place. Techniques are presented that allow estimating the oil initially in place more precisely and revising upward by 12%. Introduction The MBA fields are part of a series of simple, tilted fault-block traps formed within the rifted, Tertiary Barmer basin. Wells encountered gross oil columns in excess of 500 ft within the Fatehgarh sandstones of Late Palaeocene age. The Fatehgarh sandstone consists of interbedded sands and shales and has been subdivided into the lower Fatehgarh sandstone dominated by well-connected sheet-flood and braided-channel sands and the upper Fatehgarh sandstone dominated by sinuous, meandering, fluvial-channel sands. The sands consist almost entirely of mature quartz grains, with virtually no diagenetic alteration, high primary porosities, and excellent permeabilities. Porosities range from 17 to 33% (average 26%) with in-situ permeabilities of 200 md to more than 20 darcies (average 5 darcies). Oil from the MBA fields is waxy sweet crude with gravity ranging from 18 to 20°API close to the oil/water contact (OWC), where the crude has been slightly biodegraded, to 29°API higher in the oil column (average of 27°API). The crude has a low gas/oil ratio of approximately 180 scf/bbl, and the in-situ oil viscosity above the biodegraded zone ranges from 9 to 22 cp. An appraisal program was carried out in 2004–05, with the drilling of 20 wells, acquisition of 3D-seismic surveys, and an extensive coring and testing program including multiwell-interference tests. Areal-interference tests between wells separated by up to 4,900 ft have confirmed excellent lateral continuity within the Fatehgarh reservoir. Test rates in excess of 5,000 BOPD with limited drawdown have been achieved from MBA-field wells, confirming the high deliverability of the reservoir as inferred from logs and demonstrated with core data. Available Data Log Data. All MBA-field wells have full logging suites as well as image-log data. Eighteen wells have nuclear-magnetic-resonance (NMR) data. Fourteen wells were drilled with a water-based mud (WBM) containing appreciable amounts of potassium (>20,000 ppm), either in the form of potassium chloride or as potassium sulfate. The remaining wells were drilled with a synthetic-oil-based mud (SOBM), including wells Mangala-7ST and Bhagyam-5, which were fully cored across the reservoir unit.

Reservoir Crude Oil Viscosity Estimation From Wireline NMR Measurements - Rajasthan, India

Summary In 2004, the Mangala, Aishwariya, and Bhagyam fields were discovered in Rajasthan, India. In these high-permeability paraffinic reservoirs, viscosity is one of the main factors controlling performance. Pressure, volume, and temperature (PVT) data show areal and vertical variations in crude properties. Meter-by-meter geo-chemical core analyses corroborate vertical variations in oil composition. Continuous wireline measurements of nuclear magnetic resonance (NMR) properties and station NMR properties from wells drilled with both water-based muds (WBM) and synthetic oil-based muds (OBM) were also used to calculate a viscosity profile. This paper correlates results from all techniques and shows how NMR measurements can provide oil viscosity profiles in com-positionally complex pools. Black-oil PVT samples typically test several meters of reservoir, while Rajasthan geochemical data are available at meter scale. NMR logs provide continuous data, and calibrated to PVT and geochemistry, they can provide the most detailed picture of in-situ viscosity variations. Results were used to construct a detailed spatial description of the reservoir's in-situ oil viscosity. The NMR data helped to define a zone of biodegraded oil up to ∼25 m thick above the oil-water contact (OWC) and showed thin accumulations of higher-viscosity oil on top of minor shale layers within oil columns. The major conclusion is that detailed in-situ oil viscosity profiles can be developed from conventional wireline T2 measurements.

Variations in wetting behavior of mixed-wet cores resulting from probe oil solvency and exposure to synthetic oil-based mud emulsifiers

Mixed wettability (MXW) results from adsorption from crude oil on rock surface which is not overlain by bulk water. Crude oil/brine/rock interactions and their effect on oil recovery are often investigated after replacing the crude oil with a mineral oil. If crude oil is displaced directly by mineral oil, extreme wettability alteration, referred to as MXW-DF (direct flood), is observed. Less change is observed if an intermediate solvent, such as decalin, is used to avoid destabilization of asphaltenes contained in the crude oil; wettability conditions attained by this treatment are referred to as MXW-F (film). The oil used in a displacement test is referred to as the probe oil, the most common choice being either crude oil or mineral oil. There is strong practical interest in developing MXW-F cores that have wetting properties that are comparable to wettability at reservoir conditions. The main objective of this work is to compare the effect of probe oil solvency, characterized by refractive index, on wetting behavior, characterized by spontaneous imbibition, with MXW wettability given by the parent crude oil. The tested probe oils included mineral oils, alkanes, decalin, toluene, alpha-methylnaphthalene (AMN), crude oils and modified crude oils with both increased and reduced solvency, and base oils and solutions of emulsifiers used in synthetic oil-based mud (SBM) formulations. Wettability established by direct displacement of crude oil with an alkane (MXW-DF) showed systematic increase in water wetness with increase in solvency of the probe oil. Other approaches to tuning MXW-F wettability states by choice of probe oil are also presented. Base oils used in the formulation of SBM had essentially no effect on the imbibition behavior of MXW-F, whereas exposure of MXW-F cores to two kinds of emulsifier resulted in persistently suppressed imbibition for a wide range of probe oils.

Development of the Alba Field—Evolution of Completion Practices, Part 2: Openhole Completions, Conventional Gravel Packing After Drilling With SOBM

Summary Chevron has been successfully drilling and gravel packing openhole horizontal wells in the Alba field (central North Sea) since 1998, and 13 openhole gravel-packed (OHGP) wells drilled with water-based mud (WBM) are currently in production with no history of sand production. Although these wells have been hugely successful with significant net present value (NPV) returns, it was recognized that the future, mature redrill and infill targets cannot sustain the current costs associated with traditional OHGP completions. The challenge was to develop alternative techniques to maintain the benefits of OHGP wells but to achieve a low-cost well and completion concept to assist in realizing new drilling opportunities. Drilling the shale above the top of the reservoir and the productive interval in a single hole section would require removing conventional requirements for setting an additional casing string and changing over to a water-based system before drilling into the reservoir. This would save costs but raises a question concerning the gravel-packing operation. Hitherto, attempts to gravel pack that involve alpha/beta placement techniques using an aqueous carrier fluid following drilling with oil-based systems have had only limited success. The prospective problems were examined by extensive laboratory tests carried out cooperatively by Baroid and Chevron. A new, synthetic oil-based mud (SOBM) formulation was developed, and compatible displacement fluids and procedures were devised. Based on this work, 1,500 ft of shale and reservoir were drilled, a liner that was predrilled over the reservoir section was installed, and screen was run inside the liner. Gravel was pumped using brine as the carrier fluid, and complete gravel placement was achieved. The well has achieved productivity levels at least as good as existing WBM wells. A second well completed in the same manner has given a similar performance. This combination of a liner system and SOBM fluids offers several advantages. There is the prospect of considerable savings with respect to operating time, cementing, and drilling fluids. The liner also gives protection to the screen. This new approach, which represents potential large savings in costs and excellent productivity, is considered applicable to other types of completions when it is desirable to drill with oil-based mud even though conventional thinking would have called for water-based drill-in fluid. This consideration applies to targets in the Alba field and worldwide.

Seismic response of Gulf of Mexico reservoir rocks with variations in pressure and water saturation

The reservoir in this study is a massive turbidite in the Gulf of Mexico. A very generalized north-south cross-section (Figure 1) shows the three wells used in this study. Of particular importance are (1) the 2530 ft (TVD) between the top of the reservoir and the lower oil-water contact and (2) the perched water table on the south end of the structure. The discovery well (well 1) was drilled with water-based mud. Subsequent wells were drilled with synthetic oil-based mud. The importance of this lies in the variations in well-log response due to differences in invasion and physical characteristics of the mud filrate and the mud effects on dehydration of the clays. Continuous core was cut in well 3 from above the reservoir to 20 ft below the oil-water contact (300 ft). Detailed thin section work and special core analysis indicated a well sorted clean sand with a porosity of 27–29 pu and a permeability of 1–3 Darcys, which is typical of sands in the area. Figure 1. Generalized cross-section of the reservoir with the location of the wells used in this study. The three wells were drilled under 2700 ft of water and are scheduled for subsea completion with a tieback to a platform to the north. As a result, there will be very limited re-entry potential to run production or cased hole logs to monitor reservoir dynamics. The aquifer to the north is quite extensive and is believed to be able to provide adequate pressure for the production life of the reservoir. The current deep oil-water contact is quite apparent on both the raw 3-D seismic data and the inverted acoustic impedance cube. This study was undertaken to (1) better understand the variations in the sonic log responses in the reservoir and (2) determine if changes in reservoir pressure and …