As oil companies have moved to more-marginal reservoir targets, application of conventional techniques has often yielded disappointing results, and tighter zones are often abandoned for more-promising target intervals. Marginal reservoirs may require horizontal-well drilling or multiple-stage hydraulic fracturing to achieve economic production targets. In an effort to reduce risks and costs associated with these alternative processes, a new stimulation strategy has been adopted for tight intervals using vertical wells before going to horizontal wells.
Resources Availability
There are tens of undeveloped reservoirs and even undiscovered plays/prospects in the area of this study (Abu Dhabi). These new plays and undeveloped reservoirs contain huge quantities of stock-tank oil initially in place (STOIIP). Most of these reservoirs are still in the appraisal phase, and tremendous efforts are required to bring the best reservoirs to the top of the development portfolio. The decision to transfer a single reservoir from appraisal to development mostly depends on STOIIP ranking, which in turn takes into account the following factors.
Exploration-, Appraisal-, and Development-Data Investigation. The study investigates 51 reservoirs allocated within 14 fields under the appraisal portfolio, and three exploration reservoirs discovered recently after applying the new concept of fit-for-purpose acid fracturing. The work is extended to include a development reservoir in which long-horizontal-well drilling is implemented while the study recommends fracturing implementation. Fig. 1 above illustrates the distribution of STOIIP percentage among the three phases of exploration, appraisal, and development. The investigation of well-test results shows that more than 180 wells were tested in the area of the study. For 98 wells, the test results were considered inconclusive because of either reservoir tightness or improper stimulation treatment, or both.
Reservoir Ranking by STOIIP. On the basis of STOIIP ranking results, 13 reservoirs out of a total of 54 were ranked highly, with a minimum of 100 million STB. These reservoirs represent 77% of the total STOIIP of the portfolio. Not all of these high-STOIIP reservoirs could produce with matrix-stimulation treatment, however, because the permeability of 12 reservoirs is less than 4 md. In the class of reservoirs ranging between 100 and 50 million STB, 17 reservoirs represent some 17% of the total STOIIP of the portfolio. The remaining reservoirs are very small, with STOIIP values of less than 50 million STB.
Permeability and Porosity Relationship. Approximately 75% of the STOIIP in the undeveloped portfolio is contained in reservoirs with 1- to 4-md permeability. Most of these reservoirs are located within the area of fracturing technology where conventional matrix acidizing is not sufficient.
Fracturing Feasibility. An important factor in making a fracture treatment successful is a geomechanical study to measure rock mechanics and optimize fracturing design. In exploration wells, these data might not be available on time, which spurs development of a new stimulation-strategy-accelerating discovery.
Very-Tight Exploration-Oil-Reservoir Case Study
Reservoir Description. The field was discovered in 1975, with proven resources in three different deep reservoirs. Seven wells penetrated Reservoir A, as shown in the well-location map (Fig. 2). Two wells were tested (Wells 4 and 5) with matrix stimulation, which indicated no oil flow. The log interpretation showed oil-bearing capability, but, unfortunately, because of reservoir tightness, negative well tests were achieved in both wells.
In 2012, Well 8 was drilled to revisit this reservoir and perform fit-for-purpose acid fracturing to prove either additional STOIIP or dry conditions. Cores were collected and openhole logs were recorded to indicate oil-bearing capability with tightness features, with 0.5‑md average permeability, 15% average porosity, and 85% average water saturation. Most of the core consisted of hard and moderately brittle argillaceous mudstone. At 3,607 ft, a distinct change in lithology was observed, with the remainder of the core containing slightly crumbly mudstone with a light-brown oil stain. Abundant oil bleeding was also observed from the base of the core, with spotty bleeding for the upper part of the core. A new strategy was designed to improve acid-stimulation performance for the exploration and appraisal phase in tight reservoirs.
Treatment Execution. The reservoir interval (3,532–3,562 ft) was perforated underbalanced using a through-tubing gun in addition to the new stimulation tool. The well was flowed naturally to show no flow.
The conventional matrix-stimulation job was performed with 15% HCl at 50 gal/ft. The well was lifted for a long time to show traces of oil.
The second acid job was performed with 28% HCl and an increased acid volume of 75 gal/ft with a high pressure, but less than the fracturing pressure. The well was lifted again to recover 40 bbl. The bottomhole pressure and static-gradient survey was recorded with the downhole gauges. The pressure data show very slow pressure buildup. After deep investigations, acid fracturing was recommended to confirm the well potentiality for the appraisal stage.
Because of horsepower limitations of the pumping equipment available, multiple pumps were used to achieve the required pumping rates, and thus no accurate analysis of fracture closure was possible. Analysis performed was based on the pressure-decline curve only. Before the injection test, the results of a 50-bbl injection test with fresh water and no stress contrast between layers were simulated, determining that fracture height was likely to stay within the reservoir.
After the injection test, fracture simulations were performed for the main acid breakdown. Software was used to determine fracture propagation and etching in order to estimate the etched-fracture geometry for 200 bbl of 15% HCl. Because the geomechanics was largely unknown, the stress in all zones was assumed to be equal.
Although the hydraulic geometry created is significant, the etched-fracture height and half-length remain very small. The effective fracture half-length is approximately 60 ft, which is well below that required for such a low-permeability formation for the production phase.
After this treatment, the well was opened to show natural flow at 400 BOPD. This represents a great improvement when compared with the well’s production rate before the acid treatment. Also, the well’s productivity index has been improved from an estimated 0.014 to 0.078 B/D/psi.
The strategy was implemented in another two wells (one exploration gas well and one appraisal oil well). The results showed that the tight reservoirs below 2 md required fracturing technology.
Results
Current company strategy for exploration, appraisal, and development was reviewed. This current systematic approach did not include fracturing technology. Implementing fracturing in this case in the area of this study proved the discovery and was followed by two more successful cases.
The development scheme mainly depends on the appraisal-program results. If the appraisal activities cover only the sweet spots, the final development plan could be misleading. Moreover, if the technology is not available, management may exclude methods such as fracturing. Comparison of all scenarios, including fracturing technology, should be considered.
New Workflow. A new strategy is proposed to address the numerous difficulties described previously. The main points to be stressed within the new technology can be summarized as follows:
- Collect the data required for a geomechanical study.
- Consider fracturing for reservoirs with permeability lower than 4 md as an alternative option.
- Drill vertical and horizontal wells with different lengths; next, implement fracturing technology and compare the wells’ productivity vs. that of the conventional treatment.
- Link the available simulation software with fracturing software.
Development of a New Strategy for Matrix Stimulation and Fracturing Technology
Four standard steps of a current matrix-stimulation strategy (Fig. 3) are as follows:
Stage 1. After perforation, all cases were treated by matrix stimulation with 15% HCl at 50 gal/ft. The treatment performance as wellhead injection pressure vs. rate was not considered as a model for the injection and production analysis.
Stage 2. In all low-permeability cases of less than 4 md, lifting is the common step to flow the wells. Most of the wells have shown either no flow or very low rates, a result that requires repeating the stimulation.
Stage 3. The reservoir was retreated by matrix stimulation with 28% HCl at 75 gal/ft.
Stage 4. Relift to flow the wells. 52% of the tested wells showed no production after these extensive treatments.
Exploration or appraisal objectives were not achieved in most cases. Economic investigation for this case showed that the total duration required is 10 days while rig waiting. This long-duration cost is approximately USD 1.6 million.
A new optimization is recommended to achieve the exploration and appraisal targets at lower cost. This new workflow (Fig. 4) can be summarized as follows:
Stage 1. After perforation, perform matrix stimulation with 15% HCl at 75 gal/ft. While using acid treatment in the case of low or intermittent injection, acid concentration is to be increased to 28% HCl with additional volume; the case should then be remodeled to confirm the production prediction.
Stage 2. Lift to flow; if there are negative results, fracturing will be the next option.
Stage 3. Perform step-rate test to evaluate the fracturing design.
Stage 4. Perform optimized fracturing job.
Stage 5. Lift the well to flow.
Economic investigation for this case showed that the total duration required after breakdown and positive test results was 5 days while rig waiting. This duration cost USD 0.8 million. Even if the job was extended to include the fracturing, the duration will not exceed 11 days (at a total cost of USD 2.2 million). This new systematic workflow is economically more viable than the existing workflow because a cost reduction of approximately USD 1 million is achieved.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 164778, “A New Strategy To Explore Tight Oil/Gas Reservoirs: Fit-for-Purpose Acid Fracturing,” by G.M. Hegazy, SPE, and Adel M. Salem, American University in Cairo and Suez University; Shedid A. Shedid, British University in Egypt; Shouhdi E. Shalaby, Suez University; and J. Abbott, Schlumberger, prepared for the 2013 North Africa Technical Conference and Exhibition, Cairo, 15–17 April. The paper has not been peer reviewed.