Tangen, Geir Ivan (Lundin Norway AS) | Smaaskjaer, Geir (Lundin Norway AS) | Bergseth, Einar (Lundin Norway AS) | Clark, Andy (Lundin Norway AS) | Fossli, Børre (Enhanced Drilling AS) | Claudey, Eric (Enhanced Drilling AS) | Qiang, Zhizhuang (Enhanced Drilling AS)
In 2015, while coring in the carbonate reservoir in the second appraisal well on an oil and gas discovery in the Barents Sea (386 m water depth), the drill string fell 2 meters and a total mud loss was experienced leading to a well control incident. As a result, since 2016, the operator has introduced and used the Controlled Mud Level (CML) system. To date this system has been used on seven wells including two further appraisal wells on the same field and five exploration wells in the area.
In 2017 it was decided to drill a horizontal well in the same carbonate reservoir and to perform an extended production test in close proximity to the original loss well. Since it is not possible to predict where large voids (karsts) and natural fractures could be encountered, contingency to handle high losses, had to be implemented for the horizontal well. During the well planning, further risk reducing measures were implemented, including the use of wired drill pipe to improve the management of the wellbore pressure profile. This paper describes the planning processes leading up to the operation and the highlights of the operation itself together with the lessons learned. It elaborates on how wired pipe, used in combination with the CML system, added value to the operation. It shows how it was possible to drill the reservoir section with a low overbalance while managing severe losses associated with open karsts and natural fractures and still maintaining the fluid barrier. Despite the severe losses encountered it was possible to safely drill and complete the well without any well control event by use of the CML system.
Burgan Marrat, a deep carbonate reservoir was transferred from exploration to development team for an accelerated production of the newly discovered oil. This multi-billion barrel reservoir is spread over 450 km2, has more than 40 faults, 8 compartments with large variation in oil-water contact and reservoir/fluid characteristics. The objective of this work is to understand the key uncertainties and quantify their impact on the reservoir offtake rate and oil recovery by conducting uncertainty assessment.
An interdisciplinary team identified the key uncertainty parameters expected to have significant impact on the reservoir development. The range and probability distribution law for each parameter was set considering the uncertainties due to limited measurements or variation in interpretations. A Response Surface Model (RSM) was created to evaluate the uncertainties by using a base dynamic model and applying an appropriate experimental design, which allowed to efficiently study the uncertainty space with a feasible number of simulations. Using the RSM, the primary effects and interaction between parameters were quantified to rank the uncertainties based on their impact on field production.
Key uncertainty parameters were identified including eight OWCs, six fault transmissibilities, horizontal and vertical permeability multipliers, and porosity multiplier. Latin Hypercube was found to be the appropriate Experimental Design for the study considering 17 parameters and the need of building a reliable RSM that includes interactions between them. The design recommended 155 simulation cases, which were prepared and submitted automatically by the software.
Multi-time Responses were analyzed qualitatively to identify the top 5 uncertainties having material impact on field production over 20 years considering 6 existing wells and 30 new well locations. The RSM quantitative evaluation showed three parameters (OWC2, OWC4 and OWC1) having a total effect on the response higher than 10%; followed by PERMX and OWC3 with less than 5%. The other 12 parameters have total effects less than 2%, and the interactions effect is less than 0.5% for any interaction between two parameters. Contrary to the intuition, none of the faults proved impact on the reservoir production.
The results prove very useful to make a right development and appraisal strategy in early life of the reservoir. The new well locations can be ranked and prioritized to optimize the development and effectively appraise the areas with high risks.
Uncertainty assessment has value throughout the life of the reservoir. However, this study indicates that its application in early life of the reservoir can bring immense value. An uncertainty analysis on the reservoir production helps in decision-making regarding the number of wells and their locations to reach a target production by managing the risks.
In-situ gelled acids have been used for acid diversion in heterogeneous carbonate reservoirs for more than two decades. Most of the gelled systems are based on an anionic polymer that has a cleaning problem after the acid treatments that leads to formation damage. This work evaluates a new cationic-polymer acid system with the self-breaking ability for the application as an acid divergent in carbonate reservoirs.
Experimental studies have been conducted to examine the rheological properties of the polymer-based acid systems. The apparent viscosities of the live and the partially neutralized acids at pH from 0 to 5 were measured against the shear rate (0 to 1,000 s-1). The impact of salinity and temperature (80 to 250°F) on the rheological properties of the acid system was also studied. The viscoelastic properties of the gelled acid system were evaluated using an oscillatory rheometer. Dynamic sweep tests were used to determine the elastic (G’) and viscous modulus (G") of the system. Single coreflood experiments were conducted on Indiana limestone cores to study the nature of diversion caused by the polymer-acid system. The impact of permeability contrast on the process of diversion was investigated by conducting dual coreflood experiments on Indiana limestone cores which had a permeability contrast of 1.5-20. CT scans were conducted to study the propagation of wormhole post acid injection for both single and dual corefloods.
The live acid system displayed a non-Newtonian shear-thinning behavior with the viscosity declining with temperature. For 5 wt% HCl and 20 gpt polymer content at 10 s-1, the viscosity decreased from 230 to 40 cp with temperature increasing from 88 to 250°F. Acid spending tests demonstrated that the acid generated a gel with a significant improvement in viscosity to 260 cp (at 250°F and 10 s-1) after it reached a pH of 2. The highly viscous gel plugged the wormhole and forced the acid that followed to the next higher permeability zone. The viscosity of gel continued to increase until it broke down to 69 cp (at 250°F and 10 s-1) at a pH of 4.8, which provides a self-breaking system and better cleaning. Coreflood studies indicated that the wormhole and the diversion process is dependent on the temperature and the flow rate. There was no indication of any damage caused by the system. The injected acid volume to breakthrough (PVBT) decreased from 2.2 to 1.4 when the temperature increased from 150 to 250°F.
The strong elastic nature of the gel (G’= 3.976 Pa at 1 Hz) formed by the partially neutralized acid system proves its suitability as a candidate for use as a diverting agent. This novel acid-polymer system has significant promise for usage in acid diversion to improve stimulation of carbonate reservoirs.
Gutierrez, Mary Ellen (Universidad Industrial de Santander) | Gaona, Silvia Juliana (Universidad Industrial de Santander) | Calvete, Fernando Enrique (Universidad Industrial de Santander) | Botett, Jesus Alberto (Universidad Industrial de Santander) | Ferrari, Jean Vicente (Universidade de Sao Paulo)
About half of the world's oil reserves are in carbonate reservoirs, and most of these formations are mixed-wet or oil-wet and fractured, with extremely heterogeneous porosities and permeabilities. Implementation of enhanced oil recovery (EOR) techniques in this kind of reservoir is essential to achieve peak oil production and increase the recovery factor. Chemical EOR (CEOR) processes have been studied for many years in carbonate reservoirs but are not usually economically viable. Surfactant flooding has been considered as one of the most promising techniques among the chemical recovery methods due to the capacity of some surfactants to alter the carbonate rocks' wettability. However, the process is economically feasible only when losses of surfactant caused by adsorption into the porous media are decreased. Adsorption of surfactants can be affected by the surface charge on the rock surface and fluid interfaces. In general, the adsorption of cationic surfactants on carbonates is lower in comparison with other surfactants. Nevertheless, the high cost of cationic surfactants compared to anionic ones has led to studies aiming to evaluate the injection of the latter in the presence of a sacrificial agent in order to reduce the adsorption caused by interaction between the negative charges of the surfactant and positive charges on the carbonate surface. This work aims to study the effect of the presence of two chemicals, normally applied as scaling and corrosion inhibitors, on reducing the static adsorption of an anionic sodium olefin sulfonate surfactant on a carbonate rock. Water soluble poly(sodium methacrylate) (PSM) and diethanolamine (DEA) were evaluated as sacrificial agents in concentrations close to their scaling and corrosion inhibitor functions, respectively, to verify their sacrificial role in a co-injection chemical scenario. Adsorption studies were carried out using a pulverized carbonate rock in which low-salinity water was used as the base medium. Aqueous stability tests were carried out, which made it possible to select the correct salinity for the solutions of surfactant. Surface tension measurements were used as an indirect approach to study the adsorption of the surfactant in the presence and absence of PSM and DEA. Individually, PSM presented the best performance in reducing the adsorption of the anionic surfactant, while the DEA showed an almost null effect. However, when the chemicals were mixed, a synergistic effect was observed. The performance of PSM can probably be attributed to a steric effect of an adsorbed layer of polymer. It will be shown that even at lower concentrations, co-injection chemicals which are used for targeting other issues, such as scaling and corrosion inhibitors, may play the role of a sacrificial agent in reducing the adsorption of anionic surfactants, which is a concern in application to carbonate reservoirs.
Carbonate reservoir matrix acidizing is commonly conducted with HCl. In these treatments, HCl acid is used to create conductive channels (wormholes) to enhance well productivity/injectivity. However, its use has been limited due to associated rapid tubulars corrosion and formation face dissolution, especially in deep hot reservoirs. Emulsified acid was used as an effective alternative to HCl, but it is associated with drawbacks such high friction losses and emulsion stability. In this paper, an aqueous single-phase retarded HCl alternative system was evaluated as an alternative to straight and emulsified acid fluids.
Coreflood experiments were conducted using Indiana limestone core plugs at 180 and 270°F. Computerized Tomography (CT) scan analysis was conducted on the core plugs before/after coreflood testing. Compatibility testing was conducted on prepared retarder acid recipes. ESEM, TGA, and ICP analysis was used to analyze prepared retarder acid recipes and associated solids. Turbiscan LAB was used to assess the stability of the retarded acid recipes.
The low pore volume to breakthrough (PVBT) values (i.e., 0.9-1.6) obtained from coreflood testing at 180 and 270°F, confirmed the retarded HCl acid recipes were effective to stimulate carbonate reservoirs. Compatibility testing showed presence of significant white precipitate. ESEM analysis showed the precipitates were rod-like crystals composed of mainly of Cl and high C with small amounts of N, O, Al and Mg. TGA results showed the major constituent of precipitate were organic-based materials. The precipitate was mainly H4EDTA and chloride. Despite presence of white precipitate at the core inlet, the effect on the performance of the retarded acid system was insignificant. CT scanning analysis of the plug samples before/after the coreflooding experiments showed that wormholes along the plug length with multiple branches were formed in all cases indicating the compatibility of the selected acid recipe.
Sokhanvarian, Khatere (Sasol Performance Chemicals) | Stanciu, Cornell (Sasol Performance Chemicals) | Fernandez, Jorge M. (Sasol Performance Chemicals) | Ibrahim, Ahmed (Texas A&M University) | Nasr-El-Din, Hisham A. (Texas A&M University)
Matrix acidizing is used for permeability and productivity enhancement purposes in oil and gas wells. Hydrochloric acid has been always a first choice due to so many advantages that it can offer. However, HCl in high pressure/high-temperature (HP/HT) wells is a concern because of its high reactivity resulting in face dissolution, high corrosion rates, and high corrosion inhibition costs. There are several alternatives to HCl, among them emulsified acid is a favorable choice due to inherent corrosion inhibition, deeper penetration into the reservoir, less asphaltene/sludge problems, and better acid distribution due to its higher viscosity. Furthermore, the success of the latter system is dependent upon the stability of the emulsion especially at high temperatures. The emulsified acid must be stable until it is properly placed and it also should be compatible with other additives in an acidizing package. This study presents the development of a stable emulsified acid at 300°F through investigating some novel aliphatic non-ionic surfactants.
This paper introduces new non-aromatic non-ionic surfactant to form an emulsified acid for HP/HT wells where the conventional acidizing systems face some shortcomings. The type and quality of the emulsified acid was assessed through conductivity measurements and drop test. Thermal stability of the system was monitored as a function of time through the use of pressure tubes and a preheated oil bath at 300°F. Lumisizer and Turbiscan were used to determine the stability and average particle size of the emulsion, respectively. The viscosity of the emulsified acid was measured at different temperatures up to 200°F as a function of shear rates (0.1-1000 s-1). The microscopy study was used to examine the shape and distribution of acid droplets in diesel. Coreflood studies at low and high flow rates were conducted to determine the performance of the newly developed stable emulsified acid in creating wormholes. Inductively Coupled Plasma (ICP) and Computed Tomography (CT) scan were used to determine dissolved cations and wormhole propagation, respectively.
Superior stimulation results with low pore volume of acid to breakthrough were achieved at 300°F with the newly developed emulsified acid system. The wormhole propagation was narrow and dominant compared to branch wormholes resulted from some of the treatments using conventional emulsified acid systems. The results showed that a non-ionic surfactant with a right chemistry such as suitable hydrophobe chain length and structure can form a stable emulsified acid.
This study will assist in creating a stable emulsified acid system through introducing the new and effective aliphatic non-ionic surfactants, which lead to deeper penetration of acid with low pore volume to breakthrough. This new emulsified acid system efficiently stimulates HP/HT carbonate reservoirs.
Acidizing in un-fractured carbonate reservoirs has been well studied through modeling and simulation. Since carbonate reservoirs are often naturally fractured, fractures should be modeled for realistic acidizing operations. We present adaptive enriched Galerkin (EG) methods to simulate acidizing in fractured carbonate reservoirs. We adopt a two-scale continuum model for the acid transport. The coupled flow and reactive transport systems are spatially discretized by EG methods. Fractures are introduced using local grid refinement (LGR) technique. Adaptive mesh refinement (AMR) is implemented around wormhole interfaces. Simulation results show that acidizing in fractured carbonate reservoirs is largely dependent on the fracture system while acidizing in unfractured carbonate reservoirs is mainly determined by operation parameters such as acid injection rate. Computationally, the proposed EG scheme has less numerical dispersion and grid orientation effects than standard cell center finite difference/volume methods. AMR is very efficient to track the wormhole growth and speed up acidizing simulations.
Polylactic Acid (PLA) is increasingly used in the oil industry and specifically for diversion in matrix acidizing as evidenced by a number of field cases recently published. The solid polyester is particularly attractive due to its ability to degrade in the presence of water and heat, negating the need for cleanup fluids or complicated procedures. A majority of the analysis on the effectiveness of PLA thus far comprises experiments on artificially created slots, filter cake analysis, and field trials. This paper demonstrates the effect of PLA in wormholes developed by acidizing outcrop cores.
In these experiments, a wormhole is generated in a portion of the core by limiting the amount of acid injected. Next, the PLA is injected into the core using a heavy brine suspension. Finally, more acid is injected until a wormhole breaks through the core. Computer Tomography (CT) scans are taken, and the pressure drop across the core is recorded at each stage. Experiments were conducted for a variety of initial wormhole lengths.
It can be difficult to suspend PLA while injecting it through a core in a way that is benign to the core, acid, and PLA; and in a way that does not add any pressure drop or diversion due to viscosity changes. This paper describes and justifies a suitable method of keeping PLA suspended to allow its use in core flood experiments. The CT scans show that even when the PLA plugs the wormhole, additional acid tends to continue to develop the dominant wormhole. The pressure drop profiles show that the pressure drop due to PLA injection is proportional to the mass of PLA, both in the wormhole and on the core surface. The pressure profiles also show that there is an increased pressure drop due to PLA in the wormhole versus in a filter cake on the surface.
This paper details a new method of visualizing and analyzing the effect of PLA in a multistage acidizing treatment. Empirical correlations are presented for estimating the pressure drop caused by PLA, both as a filter cake on the formation surface and as a filling inside wormholes. The correlations were incorporated in a comprehensive carbonate acidizing model to predict the diversion efficiency of PLA particles. The simulation is verified using published field trials of diversion treatments.
The optimum design of matrix acidizing treatments in carbonate reservoirs requires accurate modeling of wormhole propagation. While there are several wormhole correlation models available, most are developed based on small core scale experiments, and result in significant deviation when upscaled to field treatment design. There also exists simulation models (e.g. Two-Scale Continuum or Pore Network models). These models are not practical for field design because of the extensive computation effort involved. Large variations in the wormholing behavior are observed in laboratory experiments using different core sizes and geometries (radial flow versus linear flow). This variation is not captured in the previous models. This work proposes a new multiscale wormhole model that represents the physics of wormholing behavior in matrix acidizing of carbonates both at core and field scales.
The derivation of the new semi-empirical model is formulated to represent the experimental data for different core dimensions and flow geometries, as well as field results. In core flooding experiments with different core sizes, the obtained pore volumes to breakthrough and optimal injection velocity are different for each core size. The same behavior is observed in numerical simulations using the Two-Scale Continuum model. That behavior is correctly calculated with the proposed model, which accounts for the dimensions in a function with dependence of the correlation parameters on the wormholed region scale and geometry. Upscaling procedures to linear, radial, elliptical, spherical, and ellipsoidal geometries are presented.
The model's results are validated by the Two-Scale Continuum numerical simulations for both linear and radial flow and verified with experimental results with different core sizes and geometries (both linear and radial flow). We further developed the model for field application, and procedure of using the model is illustrated in the paper. The different flow geometries allow predicting the acidizing behavior in common completions, such as openhole, cased and perforated, and limited entry. The model prediction compares very well to the outcome of field cases.
The new model reproduces the fractal behavior of the dominant wormhole growth above optimal injection rate, and predicts the injection pressure dependence on time as measured experimentally. The model correctly captured the physics of wormhole propagation phenomenon.
Merza Media, Adeyosfi (Schlumberger) | Muhajir, Muhajir (Pertamina Hulu Energi Tuban East Java) | M. Wahdanadi, Haidar (Joint Operating Body Pertamina Petrochina East Java) | Agus Heru, Purwanto (Joint Operating Body Pertamina Petrochina East Java) | Anugrah, Pradana (Schlumberger) | Dedi, Juandi (Schlumberger)
Most of sedimentary basins in Indonesia contain productive carbonate reservoirs. Geologically, the reservoirs are mostly part of a reef complex and carbonate platform, with basinal areas situated mainly in the back arc of the archipelago. Many of the productive carbonate reservoirs have dual porosity systems with widely varying proportions of primary and secondary porosity. Carbonates of the Tuban formation in Platinum field represent two carbonate buildups identified with similar effective porosity but different productivity. This paper describes a method for characterizing secondary porosity distribution at the wellbore and field scales to address the productivity difference between the northern and southern carbonate buildups in this field.
To resolve the challenges in characterizing secondary porosity in a carbonate formation, an integrated workflow was developed that consists of combination of quantitative and textural analysis based on borehole images at the single-wellbore scale and the seismic inversion result to control lateral distribution at the field scale. Analysis based on borehole image log provides high-resolution porosity characterization based on its size, interconnectivity, and type. The result of the single-wellbore analysis will be distributed at the field scale with control of a seismic attribute such as acoustic impedance (AI). Acoustic impedance is built with stochastic seismic inversion to provide a higher-resolution result compared to the deterministic seismic inversion method.
The result of the analysis based on borehole images at the single-wellbore scale shows most of the northern carbonate buildup wells demonstrate high development of porosity from interconnected vugs, leading to a relatively high permeability interval. In contrast, the southern carbonate buildup wells demonstrated low secondary porosity development. Low secondary porosity development is related to cemented zones and the predominance of claystone facies in a well. Later, the result of the single-wellbore scale analysis was distributed at the field scale with seismic attribute control such as AI. The Platinum field shows a negative correlation between AI and porosity with a value of -0.769; hence, the acoustic impedance from stochastic seismic inversion can be used to control the porosity distribution. The secondary porosity model shows a distinct difference between the northern and the southern carbonate buildups. The northern carbonate buildup has higher average secondary porosity compared to the southern carbonate buildup. The result was confirmed with production data; the northern carbonate buildup has higher productivity compared to the southern carbonate buildup.
This integrated workflow provides a comprehensive and high-resolution analysis of secondary porosity distribution at the single-wellbore scale and the field scale. Thus, this workflow can reduce uncertainty during reservoir characterization, well placement, and production planning.