Scale formation in oil and gas wells is a common and persistent problem during production, treatment, transportation, and disposal of co-produced salt water. Inhibition of this scale formation is priority. The most common mineral scale materials are calcite ($CaCO_3$) and barite ($BaSO_4$). The primary focus of this research is the formation and control of the sparingly soluble mineral scales. The research on scale formation was focused on measuring and predicting the rate and amount of scale formation under different conditions of temperature, pressure and brine composition. The scale prediction program ScaleChem was used to asses the nature and extent of scaling problems that may be encountered on studied oil fields. The efficiency of the inhibitors was tested for dynamic scale inhibition efficiency at the 60 °C field temperature. This technique allowed identification of scale inhibitor efficiency under dynamic flowing conditions with the results providing a guide to the working minimum inhibitor concentration in the field. Although waterflooding is a common method for increasing oil recovery, certain production problems may arise after water breakthrough. In addition to affecting oil recovery, these problems may also have an adverse impact on the environment. One particular production problem is mineral scale formation due to mixing of incompatible brines. For example, barium sulphate formation in the production well and tubulars occurs in many oil fields when sulphate rich injection water mixes with barium rich formation water close to or in the wellbore. Understanding where the scale forms is important when attempting to prevent it damaging productivity. Variation of pH in the flowing, fluid is an indicator of the degree of chemical activity occurring in the formation. High pH promotes scale deposition within the porous media and consequently particle bridging at the pore throats. The experimental investigation was made up of core flow experiments in crushed limestones. Effluent pH and concentrations were measured at the outlet of the porous medium. Brines were prepared with sodium, calcium and potassium salts $(NaCl, CaCl_2, KCl)$. Formation water used in injection and artificially prepared brine in various concentrations were caused the scale deposition. High pH values were measured in produced water caused the scale deposition. The scale deposition was decreased using NaCl, $CaCl_2$ and KC1 mixtures.The two scale inhibitors used in this study were methylene fosfonik acid (DETPMP) and sulfonated polymaleik acid co-polymer (S-PMA). Static adsorption tests were conducted using chips of reservoir core materials. All tests were conducted to examine the interaction of the scale inhibitor chemical with the reservoir core material. Laboratory coreflooding tests have demonstrated that in-situ precipitation of barium sulphate occurs when synthetic raw seawater containing sulphate is mixed in situ with a formation water that contains a significant amount of dissolved barium ions. Static inhibition experiments show that in a given brine, less percentage inhibition of barium sulfate scale is achieved at 25 °C than at 60 °C by the same amount of either DETPMP or S-PMA. A series of experiments were performed in order to rank the scale inhibitors and acid systems selected for prevention of CaCOs deposition in the study. HEDP (1-hydroxyethlene disphösphonic acid), PAA (Polyacrlyic acid), HC1 (hydrochloric acid) and Acetic acid were used to study calcium carbonate dissolution at reservoir temperature. Two of the scale dissolvers gave results better than the 15 % acetic acid system and 7.5 % HC1 system.