Nagar, Ankesh (Cairn Oil & Gas – Vedanta Limited) | Dangwal, Gaurav (Cairn Oil & Gas – Vedanta Limited) | Maniar, Chintan (Cairn Oil & Gas – Vedanta Limited) | Bhad, Nitin (Cairn Oil & Gas – Vedanta Limited) | Goyal, Ishank (Cairn Oil & Gas – Vedanta Limited) | Pandey, Nimish (Cairn Oil & Gas – Vedanta Limited) | Parashar, Arunabh (Cairn Oil & Gas – Vedanta Limited) | Tiwari, Shobhit (Cairn Oil & Gas – Vedanta Limited)
The Mangala, Aishwaya & Bhagyam (MBA) fields are the largest discovered group of oil fields in Barmer Basin, Rajasthan, India. The fields contain medium gravity viscous crude (10-40cp) in high permeability (1-5 Darcy) sands. The fields have undergone pattern as well as peripheral water injection. In order to overcome adverse mobility ratio and improve sweep efficiency thereby increasing oil recovery, chemical EOR has been evaluated for implementation in these fields. The potential benefits from chemical enhanced oil recovery (EOR) had been recognized from early in the field development. Polymer flooding was identified for early implementation, which would be followed by stage wise implementation of Alkaline-Surfactant-Polymer (ASP) injection in fields like Mangala. Since the commencement of polymer injection, the Mangala field polymer injectors have displayed multiple injectivity issues. In addition, the Aishwarya and Bhagyam fields are dealing with low Void Replacement Ratios (VRR) for their ongoing water injection, which if not rectified could adversely affect recovery. While various types of injector stimulations are being used, injectivity increases are short lived. A new technique termed as ‘Sand Scouring’ has been successfully applied resuting in sustainable injectivity gains.
The technique involves pumping creating a small fracture with a pad injected above fracturing pressure and then scouring the fracture face with low concentration 20/40 sand slugs in range of 0.5 to 1 PPA 20/40. The treatments are pumped at the highest achievable rates with the available pumping equipment within the completion pressure limitations. Based upon the available tankage, the scheduled is designed such that pumping of a fixed volume of sand stage, a quick shut-down allows for mixing the next stage of slurry. The pumping schedule and a ‘scouring’ intent is deliberately designed to avoid requirement of fracturing equipment, related cleanout equipment and resulting costs. The challenge of conformance is addressed by designing the pumping schedule to incorporate stages of particulate diverters and validated using pre and post injection logging surveys. .
Sand scouring jobs in 16 wells have been conducted across Mangala, Bhagyam & Aishwarya injectors. Out of thesewells, 9 wells had zero injectivity while the other 7 required both injectivity and conformance improvement. Most of the treated wells resulted in multifold improvement of injectivity as compared to their prior injection parameters. Sand scouring resulted in sustained injection performance when compared with prior conventional methods of stimulation. Injectivity improvements from sand scouring lasted for an average of 3 months days as compared to 14 days for the conventional stimulations. Sand scouring evolution, design, results and plans for future improvement are all discussed in this paper.
Wang, Gang (China University of Petroleum-Beijing) | Fan, Honghai (China University of Petroleum-Beijing) | Zhang, Wei (CNPC Engineering Technology R&D Company Limited) | Yang, Yang (China University of Petroleum-Beijing) | Han, Zili (CNPC Bohai Drilling Engineering Company Ltd.) | Wu, Hongxuan (CNPC Chuanqing Drilling Engineering Company Ltd.) | Li, Wanjun (CNPC Engineering Technology R&D Company Limited) | Li, Jiaying (CNPC Engineering Technology R&D Company Limited) | Zhou, Tuo (CNPC Engineering Technology R&D Company Limited) | Zhou, Haiqiu (CNPC Engineering Technology R&D Company Limited) | Liu, Jitong (CNPC Engineering Technology R&D Company Limited)
M15 well contains complex intervals, where anticlinal structures developed from faults make long mudstone barriers full of cracks, which makes it hard to predict pore pressure. Loss is one of the most serious problems during drilling and cementing, while blow out accidents happen sometimes. Previous casing programs hardly adjust to all complex intervals and conventional LCMs (loss control materials) play few roles. As a result, designated targets used to be rarely reached.
It is proved that low pressure intervals shall be isolated firmly and complex intervals as well as reservoirs should be developed in independent intervals, thus casing programs have been modified. 188 lab tests were finalized, including 180°C hot rolling, anti-contamination test, lubricity test and inhibition experiments, in order to develop a kind of organic salt mud system that has premium inhibition, plugging, lubricating, heat & salt resistance properties. Precise MPD (managed pressure drilling) techniques are recommended to achieve near-balance drilling operation, solving borehole instability problems to some extent.
In the second interval the organic salt mud system is applied, while logging and casing running may be accomplished in one time. Besides, strings can be tripped out smoothly and high pressure brine productive zones are drilled safely. φ339.7mm casing joints are set at the depth of 3848m in the second interval and φ244.5mm casing joints are set at the depth of 5177m in the third interval, in order that deeper complex formation may be developed in a separate casing interval in which precise MPD is applied with LCMs while drilling and compound plugging agents. Therefore, downhole pressure is precisely controlled and large cracks are plugged statically on 28 occasions. Designated targets have been all reached and 20 oil & gas productive layers have been developed.
Downhole complexities arising from loss and blowout have been solved in M15, where φ339.7mm casing was set at the deepest interval in CNPC overseas operation history, making a new record of safe drilling operation, borehole quality and cementing quality. More oil and gas productive zones have been discovered and all designated targets have been achieved. New drilling experience got from M15 has significant meanings in the development of similar blocks.
We suggest two new thermodynamic models for the adsorption of ions to the brine/carbonate and brine/crude oil interface. We calibrate the model parameters to the ionic adsorption and zeta potential data. We then investigate the effect of the rock and oil surface charges on the dissolution, wettability alteration, and mechanical properties of the carbonates in the context of modified-salinity water flooding in the North Sea chalk reservoirs.
We modify a charge-distribution multi-site complexation (CD-MUSIC) model and optimize its parameters by fitting the model to a large data set of calcite surface zeta potential in presence of different brine compositions. We also modify and optimize a diffuse layer model for the oil/brine interface. We then use the optimized surface complexation models with a finite-volume solver to model the two phase reactive transport of oil and brine in a chalk reservoir, including the impact of dissolution, polar-group adsorption, and compaction on the relative permeability of chalk to water and oil. We compare the simulation results with the published experimental data.
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.
A general formulation for a coupled Thermal-Hydraulic-Mechanical with hydrate Dissociation (THMD) system is developed and applied to sand prediction for conventional gas and gas hydrate bearing sediments (GHBS). Two-phase fluid and conductive heat flow are coupled to an elastoplastic geomechanics model. Series of solutions for simplified models are presented. Fundamental geomechanics behaviors before and after plastic yielding, sanding, and gas hydrate dissociation are defined, discussed, and simulated differently and sanding onset for both conventional gas formations and GHBS are defined by an effective plastic strain (EPS) criterion. The accuracy and reliability of the proposed conventional model are verified by comparing the model prediction with the results of hollow cylinder tests on two different types of sandstone. The advantages of using the EPS over stress-based criteria as an indicator for onset of borehole collapse and sand production are discussed. Introducing a moving gas hydrate dissociation zone (front), the fundamental geomechanics behaviour and elastoplastic deformation of the skeleton formation are highlighted. The effects on sand prediction due to the characteristics of nonlinear plastic yielding criteria and gas flow in porous media are also emphasized.
Taheri, Mirhossein (Danish Hydrocarbon Research and Technology Center) | Bonto, Maria (Danish Hydrocarbon Research and Technology Center) | Eftekhari, Ali Akbar (Danish Hydrocarbon Research and Technology Center) | M. Nick, Hamidreza (Danish Hydrocarbon Research and Technology Center)
Our objective is to find an alternative approach to the history matching of the modified salinity water flooding tests in secondary and tertiary mode. Instead of matching only the recovery factor and pressure drop history, we give a higher priority to matching the different ion concentrations and oil breakthrough times. Based on these analyses, we suggest the predominant mechanisms for the modified-salinity water flooding in carbonates.
The work is done in three steps: 1) Studying a large data-set of modified-salinity water flooding experiments in carbonates. 2) Quantifying the adsorption of potential determining ions (PDIs) on the carbonate surface using an optimized in-house surface-complexation model 3) Adjusting the relative permeability parameters to history-match the experimental data using different analytical solution of water-flooding (with and without ionic adsorption) combined with modern search-based optimization algorithms. The optimization algorithm gives a high weight factor to the breakthrough time of oil and PDIs.
Having too many parameters in the relative permeability (6 parameters for Brooks-Corey type) make it possible to match any type of recovery curves. However, we found out that matching the breakthrough times, especially in the tertiary modified salinity waterflooding, can only be achieved by considering the wettability change due to the adsorption of PDIs on the carbonate surface. This observation, combined with our ability to accurately model the adsorption of PDIs on the carbonate surface, helped us to identify the important PDIs that cause the wettability change in carbonates. For instance, we observe that a model that considers the wettability change due to the adsorption of calcium ions on the chalks surface matches perfectly to the tertiary flooding of the Stevns Klint outcrop chalk with seawater. The second important observation is that the lag between the start of the injection of the modified-salinity brine and the oil breakthrough time is not always due to the adsorption of ions and sometimes can be explained by the wettability change due to the lower salinity of the injected brine. It must be noted that this new approach is still semi-empirical, and needs to be combined with more fundamental studies to identify the actual mechanisms.
Electrical-submersible-pump (ESP) technology is a proven artificial-lift method for shallow, low-pressure reservoirs such as those found in the West Sak viscous oil field in Alaska. The green light comes 4 years after the privately-held firm filed its development and production plan. Liberty Island would consist of gravel, stretch 9 acres, and sit just a few miles offshore. Major oil discoveries by Armstrong Oil & Gas and ConocoPhillips have compelled the US Department of the Interior to reassess its estimate of undiscovered, technically recoverable resources in parts of Alaska. ConocoPhillips is producing more oil from the North Slope as it advances development of the massive, historic region.
Researchers at two California universities are studying the fiery flares that pock-mark drilling sites in the Eagle Ford Shale of south Texas. Among the most consequential provisions is the permanent reauthorization of the Land and Water Conservation Fund, a federal program established in the 1960s that uses fees and royalties paid by oil and gas companies drilling in federal waters to pay for onshore conservation programs. Global climate concerns, amplified in the public consciousness by a steady stream of violent weather events such as hurricanes and California wildfires, are generating a new set of realities for the energy industry. A Florida appeals court has approved exploratory oil drilling in the Everglades, prompting worries about Miami’s water supply and risks to the wetland ecosystem. Kentucky lawmakers have introduced House Bill 199 to plug orphaned oil and gas wells and abandoned storage tanks that threaten health, safety, and the environment. A bipartisan group of House lawmakers introduced legislation that would ban oil and natural gas drilling in Alaska’s Arctic National Wildlife Refuge. Chevron plans to set greenhouse gas emissions targets and tie executive compensation and rank-and-file bonuses to the reductions, the oil major said in its latest climate report.