How Petrobras Has Faced Oilfield Scale Problems: Evolution of Concepts and Lessons Learned in Campos Basin, Brazil

Abstract

This paper is aimed at presenting how Petrobras has faced inorganic scale problems in Campos Basin oilfields, Brazil. The approach used by Petrobras to predict, prevent and correct the problem of scale formation in tubulars and surface facilities is presented on a comprehensive basis. Radioactive-scale-related problems such as: storage, handling, disposal and equipment's de-commissioning are discussed as well. Both chemical and mechanical solutions and in-house developed techniques to cope with scale inhibition/dissolution are described as well. The requirement to assure high production level from deepwater wells demands high seawater injection rates. Herewith, then, it is presently underway the assessment of a nanofiltration system to remove sulfate ions from seawater and prevent barium sulfate scale from forming. Nanofiltration employment in deepwater Roncador field is also discussed in the paper. At the end of paper case histories are presented. Introduction Inorganic oilfield scale (OS) may be defined as water-soluble (inorganic) chemical compounds that precipitate out of solution and may agglomerate in the formation, perforations, gravel pack screens, tubing and surface facilities. OS consists of inorganic salts that come out of solution when incompatible waters, viz., formation water and injection water, are mixed and the resulting solution - under given conditions - becomes supersaturated with respect to an ion. OS may also precipitate out of solution when formation water equilibrium is upset by physical and chemical changes. As formation water moves upward, from reservoir to surface, the whole well fluid stream is submitted to a gradient of pressure, temperature and turbulence. Additionally, above the bubble point, a fraction of the dissolved gas separates out of both formation water and oil phases causing a major composition change in both phases of the well flow stream. As a consequence of this, formation water moves to another point of equilibrium by precipitating out of solution its supersaturated salts. Given adequate hydrodynamic conditions these precipitates may form OS. Nucleation sites, flow regime and surface roughness are among parameters that govern OS formation from original precipitates.1 The same phenomenon happens upon the oil phase and organic compounds may also precipitate out of solution. Notwithstanding with that, it is not within the scope of this work to discuss organic deposition. OS formation poses a tremendous impact on well productivity and is known as one of most troublesome problems in the oilfield.2 The most common OS are: calcium sulfate (gypsum), calcium carbonate (calcite), barium sulfate (barite) and strontium sulfate (celestite), iron carbonate (siderite), amorphous (opal) and crystalline silica (chalcedony).3 Radioactive (radium-based) OS are also known. Campos Basin Scenario The most common OS found in Campos basin are calcium, barium and strontium sulfates. Calcium carbonate scale occurrence is rare and local. Sodium chloride (halite) scales are also known. The presence of naturally-ocurring-radioactive-materials (NORM) in oifield scale has been known since early the 1980 s in Campos Basin area. This problem has happened upon in some fields located in shallow waters of the basin, which have been submitted to a continuos seawater injection program. It has been identified that these NORM-containing OS result from small amount of radium ions leached out from reservoir rock by injection water. A part of this radium salt co-precipitates with barium and strontium as sulfates. Another part of it remains soluble in the produced water.4

Formation Damage History in the Mature Fields of Campos Basin Offshore Brazil

“…From June 1988 on evidences of scale deposition were observed in production tubing in wells with about 20% BSW, which water composition had at least 5% of sea water 17 . In October 1988 a gamma ray logging showed high readings anomalies and a sample collected downhole revealed a composition of barium and strontium sulfates with a small amount of radium 18 . Since then, the occurrence of hard scale, sometimes plugging totally the tubing, have been verified.…”

“…Scale inhibitor is also injected at the dry Christmas trees to prevent scale deposition in the production plant. The scale inhibitor technology applied in the Namorado field evolved from precipitation squeeze treatments with polyacrylic acid (PAA) to phosphino polycarboxylic acid (PPCA) 18,19 . The inhibitor precipitates on the rock matrix with the assistance of a calcium carbonate pad.…”

“…Throughout the well production the calcium carbonate is produced along with the inhibitor. However, with this technique the fixation of the inhibitor on the reservoir rock depends on the degree of distinct fluids (inhibitor and calcium pad) mixture injected into the well 18 . There were cases of poor inhibition efficiency and even formation damage related to this technique.…”

“…A few mechanical removal operations were performed with no attractive economical results. These techniques also present the problem of managing naturally occurring radioactive material (NORM) in the production platform, once that the scale contains small amounts of radioactive isotopes in the lattice 18 . It should be mentioned that the disposal of the tubing clogged with scale is a big issue that has been managed with proper procedures.…”

Assessment of Scale Formation in the Column of an Oil and Natural Gas Producing Well: A Case Study

“…A decline in production may be caused by damage or elevation problems within the formation (Mackay et al, 1999). Inorganic salt deposits, commonly known as scale, are some of the possible problems encountered during exploration and production, and can lead to reduced permeability in the hydrocarbonproducing formation due to the precipitation of inorganic salts in the reservoir, and perforations in the rock, production column and some surface equipments (Dyer and Graham, 2002;Marques et al, 2001;Mackay et al, 2003;Jordan et al, 2000;.…”